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Full text of "Small hydroelectric potential at existing hydraulic structures in California"

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state of California 
The Resources Agency 

Department of 
Water Resources 





SWilll Hydroelectric Potential at 

g Hydraulic Structures in California 



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BulleUn 21 
April 198m 



Bulletin 211 was parti; 
(No. DE-FC-49-80-R9- 

This Bulletin responds 

". . . It is in the best int 
Department of Water I 
cost-effectiveness of € 
facilities . . ." 

The legislation, Senat 



DATE DUE 


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1 I ' 

























































































LIBRARY -MP REGION 
U.S. Bureau of Reclamation 
2800 Cottage Way 
Sacramento, CA. 95825 



aulic structures identified in the 
o determine the feasibility and 
with electric power-generating 



St. 




ON THE COVER Turlock Lake 
Powerhouse, located on the Turlock Main 
Canal in Stanislaus County, is owned by the 
Turlock Irrigation District This 3 300- 
kilowatt hydroelectric power plant 
generates 12 2 million kilowatthours o1 
electricity annually This amount of energy 
is equivalent to burning 20,000 barrels ot oil 
annually in a fossil fuel plant 



Photo courtesy of Turlock Irrigation District. 



Department of 
Water Resources 

Bulletin 211 



lOM.OO 
OHM 



Small Hydroelectric Potential at 

Existing Hydraulic Structures in California 



April 1981 



Huey D. Johnson 

Secretary for Resources 

The Resources 
Agency 



Edmund G. Brown Jr. 


Ronald B. Robie 


Governor 


Director 


State of 


Department of 


California 


Water Resources 



FOREWORD 

To help meet California's increasing need for electricity, the 
Department of Water Resources is actively studying potential sources of 
hydroelectric energy in the State. The development of small hydroelectric 
generation facilities at existing hydraulic structures is one 
environmentally sound energy resource that merits the highest priority. 

In 1978, the California Legislature enacted Senate Bill 1834 
(Chapter 933, Statutes of 1978, authored by Senator Alfred Alquist) which 
directed the Department of Water Resources to study the feasibility and 
cost effectiveness of equipping existing dams and other hydraulic struc- 
tures with electrical power-generating equipment. 

The Department began its study by identifying 285 potential sites for 
developing small hydroelectric facilities through questionnaires sent to 
irrigation districts. Federal and State water agencies, and public and 
private utilities. These sites would have a total capacity of about 
500 megawatts and an annual energy generation of 2.4 billion kilowatthours . 
Through this survey and subsequent studies, the Department determined that 
240 out of 285 potential sites, representing 99 percent of the total poten- 
tial capacity, would be cost effective by 1989. This could supply the 
residential needs of one million people and would eliminate the need of 
burning 4 million barrels of oil yearly in a thermal power plant. 

In January 1980, Governor Edmund G. Brown Jr. established a task force 
headed by this Department and comprised of representatives from nine State 
agencies to support and encourage the construction of power plants at 
existing dams, canals, and pipelines. Through the efforts of this task 
force, the process for obtaining State permits and approvals for hydroelec- 
tric power plants has been streamlined. The Department of Water Resources, 
in cooperation with the U. S. Department of Energy, has also established an 
"Outreach Program" to assist developers with procedural requirements and to 
provide loan information for small hydroelectric projects. Information 
regarding hydroelectric development can be obtained by telephoning 
(916) 323-0103. 

This study is a comprehensive analysis of small hydropower, and is a 
significant step towards establishing energy independence, not only in 
California, but also elsewhere in the nation. As part of meeting its goal 
of satisfying 70 percent of the State Water Project's energy needs from 
renewable resources, the Department of Water Resources has scheduled the 
construction of 15 small hydroelectric power plants at sites on the State 
Water Project . 

Small hydro efforts are growing. As a result, the State should gain 
about 500 megawatts of small hydroelectric capacity within the next ten 
years. This is a significant step in achieving the State's and nation's 
energy goals. 




6 




Ronald B. Robie, Director 
Department of Water Resources 
The Resources Agency 
State of California 



%%v 



Copies of this bulletin at $5.00 each, 
and the Appendixes bound separately 
in a single volume at $10.00 each, 
may be ordered from: 

State of California 

nwR 

p. 0. Box 388 
Sacramento, CA 95802 
Make checks payable to 
DEPARTMENT OF WATER RESOURCES 
California residents add 6% sales tax 



See page viii for list of Appendixes 
(bound separately) . 



^y 



CONTENTS 

Page 

FOREWORD iii 

ORGANIZATION ix 

CALIFORNIA WATER COMMISSION x 

SUMMARY 1 

I. INTRODUCTION 3 

Small Hydroelectric Technology 6 

Environmental Issues 7 

Economic Issues 8 

Retrofitting Problems and Their Solution 10 

Physical and Hydrologic Requirements 11 

Status of Facility Development 12 

II. THE PURCHASE OF SMALL HYDROELECTRIC POWER BY UTILITIES 23 

Pertinent Legislation 23 

Cost of Alternative Generation 25 

Estimated Payments for Hydroelectric Generation 31 

III. SELECTION AND EVALUATION 35 

Selection 35 

Field Investigations 38 

Feasibility Studies 39 

Guidelines 39 

Assessment of 28 Sites by the Department of Water Resources 47 

Assessment of 42 Sites by Others 49 

Assessment of 215 Sites From Data on Questionnaires .... 51 

Summary of Assessment 51 

IV. PROCEDURES FOR SITE DEVELOPMENT 67 

Reconnaissance Survey 68 

Preliminary Permit Application 68 

Preliminary Feasibility Study 70 

Feasibility Loan Application and Processing 70 

Final Feasibility Study 71 

Licensing Loan Application and Processing 72 

License and Permit Approvals, and Environmental Review. . . 72 

Financing 73 

Design and Construction 73 



CONTENTS (Continued) 

Page 
GLOSSARY 75 

FIGURES 

1. Number, Capacity, and Energy of Cost-Effect ive Projects 2 

2. Potential SmalL Hydroelectric Sites at Existing Facilities ... 4 

3. Cost of Oil-Fired Generation at PG&E's Most Efficient 

Steam Plants 24 

4. Cost of Oil Burned for Electric Generation Middletown Station- 

Hartford Electric Lighting Company Hartford, Connecticut ... 26 

5. Historical and Projected Average Cost of Oil for Electrical 

Generation at PG&E's Most Efficient Steam Electric Plants . . 33 

6. Selection and Evaluation Flow Chart 34 

7. Power Developed at Various Combinations of Head and Flow .... 40 

8. Estimated Costs of 28 Projects Studied by the Department 

of Water Resources 42 

9. Annual Cost of Owning and Operating Small Hydroelectric 

Projects 44 

10. Preliminary Assessment of 28 Sites Studied by the Department 

of Water Resources 46 

11. Estimated Project Costs for 42 Sites Studied by Others 48 

12. Preliminary Assessment of 42 Sites Studied by Others 50 

13. Typical Costs and Schedule for developing a Small 

Hydroelectric Project 69 



vv 



CONTENTS (Continued) 
TABLES 

Page 

1. Sunnnary of the Status of Small Hydroelectric Projects 

at Existing Facilities 12 

2. Detailed Analysis of the Status of Small Hydroelectric 

Projects at Existing Facilities 13 

3. U.S. Department of Energy Feasibility and Licensing 

Loans 18 

4. California Energy Commission Feasibility Study 

Grants 21 

5. CEC's Projected Prices of Oil (1979 Dollars per Barrel) . 29 

6. Annual Escalation Rates of Oil Prices (Percentage). ... 29 

7. Estimated Price of Oil (Future Dollars per Barrel). ... 30 

8. Projected Energy Rates for Sale of Small Hydroelectric 

Generation 31 

9. Capacity Payment Rates by Utilities ($/kilowatt-year ) 

Effective February 4, 1980 32 

10. Field Investigations Conducted by the Department 

of Water Resources 36 

11. Project Cost and Energy Cost in 1984 for 285 Potential 

Hydroelectric Facilities 52 

12. Summary of Facilities Cost Effective in 1984, by 1989, 

and Those Not Likely to be Cost Effective 66 

13. Steps Required to Develop a Small Hydroelectric 

Project 67 

14. Agencies Whose Approvals for Small Hydroelectric 

Projects Are Required 72 



Portions of this report were prepared with the assistance of; 



Contractor 
John J. Boudreau 
Lee Crisan 
James Hansen and Associates 

Total 



Contract No . 

B-53267 

B-53814 

B-52584 
B-53570 
B-53303 



Amount 

$ 6,452 

2,500 

2,667 

52,500 

108,802 

$172,921 



v^^ 



APPENDIXES (bound separately in a single volume) 
CONTENTS 

Appendix A: Lists of Potential Small Hydroelectric Projects At 
Existing Hydraulic Facilities In California 

Appendix B: Field Investigations Conducted by Department of Water 
Resources 

Appendix C: Preliminary Feasibility Studies for 28 Representative 
Facilities, Prepared by the Department of Water 
Resources 

Appendix D: Feasibility Studies for 42 Facilities, Prepared by 
Others 

Appendix E: Capacity, Energy, and Cost Data on Facilities Grouped 
into Six Categories 

Appendix F: Permits, Licenses, Certificates, and Other Approvals 

Appendix G: Utility Purchase Prices for Hydroelectric Generation 

Appendix H: Financing Small Hydroelectric Projects 

Appendix I: Hydroelectric Equipment 

Appendix J: Manufacturers of Small Hydroelectric Equipment 



y^^^ 



State of California 
EDMUND G. BROWN JR., Governor 

The Resources Agency 
HUEY D. JOHNSON, Secretary for Resources 

Department of Water Resources 
RONALD B. ROBIE, Director 

MARY ANNE MARK GERALD H. MERAL ROBERT W. JAMES 

Deputy Director Deputy Director Deputy Director 

CHARLES R. SHOEMAKER 
Deputy Director 

ENERGY DIVISION 

Frank J. Hahn Chief 

This report was prepared under the direction of 

Richard G. Ferreira Chief, Renewable Resources Development Branch 

Henry E. Struckmeyer .... Chief, Non-Renewable Resources Development Branch 

by 

Arnold Johnson Senior Engineer, Water Resources 

Ronald Delparte Associate Engineer, Water Resources 

Do T. Nguyen Associate Electric Utilities Engineer 

Lori Austin Graduate Student Assistant 

Angel Gutierrez Student Assistant Engineering 

Jessica Jones Student Assistant 



with 
special assistance provided by 

Earl Bingham Research Writer 

Robin Reynolds III Energy Resource Specialist I 

Fran Letcher Senior Word Processing Technician 

Clara Silva Word Processing Technician 

Pamela Casselman Word Processing Technician 

Jean Whitney Word Processing Technician 

Gayle Dowd Senior Delineator 

Mary Jane Benninger Reproduction Machine Supervisor 

and special acknowledgement to 

John E. Crawford, U. S. Department of Energy, for his assistance with this 
program, and for his comprehensive critique of the bulletin. 



2—82256 



IX 



State of California 

Department of Water Resources 

CALIFORNIA WATER COMMISSION 

SCOTT E. FRANKLIN, Chairperson, Newhall 
THOMAS K. BEARD, Vice Chairperson, Stockton 

James Shekoyan Fresno 

Roy E. Dodson San Diego 

Alexandra C. Fairless Areata 

Daniel S. Frost Redding 

Merrill R. Goodall Claremont 

Donald L. Hayashi San Francisco 

Charlene H. Orszag Sherman Oaks 



Orville L. Abbott 
Executive Officer and Chief Engineer 



Tom Y . Fuj imoto 
Assistant Executive Officer 



The California Water Commission serves as a policy advisory body to the Director 
of Water Resources on all California water resources matters. The nine-member 
citizen Commission provides a water resources forum for the people of the 
State, acts as a liaison between the legislative and executive branches of State 
Government and coordinates Federal, State, and local water resources efforts. 



X 



SUMMARY 

The Department of Water Resources studied the feasibility and cost 
effectiveness of retrofitting existing hydraulic structures within the 
State with facilities for generating hydroelectric power. 

A statewide survey identified 285 sites — 137 dams, 53 canals, and 
95 pipelines — where hydropower could be developed. These sites offered a 
combined potential for generating 510 megawatts (MW) of power with an 
annual energy production of 2.4 billion kilowatthours (kWh). 

The 285 sites were categorized into six groups, based on the type and 
size of existing hydraulic structure. From these, 49 sites were selected 
for field investigations, and preliminary feasibility studies were con- 
ducted at 28 of these representative sites. Based on these studies, the 
cost effectiveness of each site was determined, and these cost data were 
used to estimate the cost effectiveness of the remaining sites for which 
limited data were available. 

The study showed that 167 (59%) of the 285 sites are cost effective 
if developed immediately for initial operation in 1984. These sites repre- 
sent an installed capacity of about 468 MW — 92% of the potential power — 
and an estimated annual generation of 2.25 billion kWh (95%). An addi- 
tional 73 (26%) of the sites would be cost effective by 1989. These sites 
represent an installed capacity of 36 MW (7% of the potential power) and an 
annual generation of 120 million kWh (5%). Only 45 (15%) of the sites 
studied representing an installed capacity of 6 MW — 1% of the potential 
power — and an estimated annual generation 10 million kWh (0.4%) are less 
suitable for immediate development. These sites would have to operate at a 
loss for in excess of 5 years before becoming cost effective under current 
fuel cost projections. 

Progress in the development of small hydroelectric projects is 
illustrated by the number of projects completed or under construction and 
the number of permit and license applications filed with the Federal Energy 
Regulatory Commission (FERC). Out of the 285 potential projects 80 facil- 
ities — representing over 355 MW of the total installed capacity of 510 MW 
— have been completed, are under construction, or have had applications 
filed for them with FERC. 

The results of this study emphasize the value of utilizing all of 
our potential energy resources. Developing the small hydroelectric facil- 
ities identified here would make available over 2.4 billion kWh of elec- 
trical energy annually. If oil were used to generate this energy, 4 
million barrels would be required each year. In addition, 2.4 billion kWh 
of electrical energy represents a value of approximately $120 million in 
revenue each year. Development of this resource would significantly reduce 
California's dependence on imported oil, provide a dependable, 
environmentally sound source of electrical energy, and would be an 
important contribution to the nation's goal for energy independence. 



FIGURE 1 



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CHAPTER I 
INTRODUCTION 



This bulletin reports the results of a study of the feasibility of 
developing small hydroelectric power-generating facilities at California's 
existing hydraulic structures, such as dams, canals, and pipelines. By 
identifying potential sites for such development and evaluating their cost 
effectiveness, the Department of Water Resources hopes to encourage 
private, as well as public, entities to invest in the state's energy 
future . 

Although the Department only evaluated sites within the state, these 
hydraulic structures also typify those that commonly occur in other states. 
Because of this, the results of this study are freely trans ferrable nation- 
wide, and the report's findings should be beneficial to any state that is 
concerned about its energy independence. 

In 1974, a departmental report, "Hydroelectric Energy Potential in 
California" (Bulletin 194), identified potential sites for hydroelectric 
facilities that had a generation potential of more than 25 million kilo- 
watthours annually. The report inventoried hydroelectric developments that 
had been studied previously, but those which might warrant reevaluation in 
view of quadrupling oil prices. Most of the projects required the con- 
struction of new dams and reservoirs or the enlargement of existing 
facilities . 




Lake Berryessa (Monticello Dam), on Putah Creek in Napa County, is 
oimed by the U. S. Water and Power Resources Service. A 16 000- 
kilowatt hydroelectric power plant at this site could generate 43 
million kilowatthours of electricity per year. This amount of 
energy would supply the anyiual electrical residential needs of 
20,500 people. (Photo by DWR Energy Division) 



Figure 2 Potential Small Hydroelectric Sites at 
Existing Hydraulic Facilities 



TYPE OF SITE 

* DAM 

■ CANAL 

• PIPELINE 




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* P E ° ■ • ■ 1 



In 1976, the Department sent questionnaires to over 800 California 
water agencies, utilities, and federal agencies requesting them to identify 
and provide information on potential small hydroelectric projects that 
could be constructed at existing hydraulic facilities, such as dams, canals 
and pipelines. A report, "A Survey of Small Hydroelectric Potential at 
Existing Sites in California," was published as Bulletin 205 in June 1979 
based on this information. It identified 212 potential hydroelectric proj- 
ects that could be developed at existing installations. 

The Legislative directive (SB 1834, authored by Senator Alquist) to 
conduct a feasibility study became more important during the past year than 
was originally anticipated in 1978. At the time of the first oil crisis in 
1973, the average cost of oil used to generate electrical energy in 
California was $5 per barrel. The cost remained reasonably stable at about 
$15 per barrel from 1975 through 1978. After the political unrest in Iran 
in late 1978, the price of oil jumped. Shortages reappeared, and by late 
1979 the price of oil increased to about $25 per barrel and even higher on 
the spot market. The average price of oil increased to about $30 per 
barrel by mid-1980. 

Projections prepared by the California Energy Commission in late 1979 
indicate substantial increases in the price of oil will continue until 
synthetic fuels become available. Since 50 percent of California's elec- 
tricity is generated using oil, the costs of generating electrical energy 
will continue to increase. Thus California's potential hydroelectric 
resources become increasingly more valuable. 

In 1980, questionnaires were sent to utilities, water agencies, and 
irrigation districts that did not reply to the 1976 survey. About 75 addi- 
tional existing facilities were identified for a total of 285 locations 
where small power plants could be constructed (Figure 2). 




Clear Lake Impounding Dam, on Cache Creek in Lake County , is owned 
by the Yolo County Flood Control and Water Conservation District. 
A 2 000-kilowatt hydroelectric power plant at this site could gen- 
erate 7.5 million kilowatthours of electricity per year. This 
amount of energy would supply the annual electrical residential 
needs of 3j600 people. (Photo by DWE Northern District, Red Bluff) 



since it was not possible to investigate each of the 285 potential 
sites, the Department developed a three-phase evaluation program 
(Chapter III, Figure 6). During the first phase, the 285 hydraulic facil- 
ities were classified into six categories based on the size and type of 
facility. Forty-nine of these facilities were selected for field investi- 
gations during the second phase. These facilities were representative of 
the six categories. After visiting these facilities and assessing them, 
the Department selected 28 facilities which best represented most of the 
facilities in California. A preliminary feasibility study of each of these 
28 facilities was conducted during the third phase. The information from 
the 28 studies was supplemented by 42 feasibility reports prepared by inde- 
pendent consultants hired directly by facility owners. The results of the 
Department's 28 preliminary feasibility studies are discussed in Appen- 
dix C; data taken from feasibility studies conducted by others are pre- 
sented in Appendix D. The data from the 28 studies, supplemented by cost 
information from the reports prepared by independent consultants, were used 
to evaluate the cost effectiveness of all potential facilities in 
California. This assessment of statewide potential is discussed in 
Chapter III. 



Small Hydroelectric Technology 

Small hydroelectric technology was extensively developed in this 
country from the late 1800s into the 1940s. Very few small hydroelectric 
plants have been installed between 1950 and 1975, because of the more 
favorable economics of large steam-electric plants. In fact, about 
3,000 hydroelectric plants have been retired from service during the period 
from 1930 to 1970. A recent study shows that as many as 2,150 of these 
plants representing 1 300 MW could readily be returned to production. 




Lake Redding (ACID Diversion Dam), on the Sacramento River in 
Shasta County^ is owned by the Anderson- Cottonwood Irrigation 
District. A 9 000-kilowatt hydroelectric power plant at this 
site could generate 50 million kilowatthours of electricity per 
year. This amount of energy is equivalent to burning 85, ZOO 
barrels of oil annually in a fossil-fuel power plant. 
(Photo by DWR Energy Division) 



Over the past 30 years, small hydroelectric technical development also 
declined, and turbine manufacturing facilities were either abandoned or 
fell into general disuse. During this time, European and Asian manufac- 
turers continued to manufacture small hydraulic turbines, but primarily for 
power generation locally or for use in remote areas. 

Due to recent events, American manufacturers have renewed interest in 
supplying hydraulic turbines. Al lis-Chalmers Company, a major manufac- 
turer, has designed a line of standard horizontal tube-type turbines, which 
are available in ten sizes ranging between 50 kW and 7000 kW of capacity 
and for heads up to 18.3 metres (60 feet). Another manufacturer, James E. 
Leffel Company, has joined with Bofers-Nahab of Sweden and Tampella of 
Finland and is in the process of enlarging its American facilities to pro- 
duce principally site-specific vertical-type turbines. The China National 
Machinery and Equipment Export Corporation plans to aggressively market its 
hydroelectric equipment in the United States. The Schneider Lift Trans- 
lator Company builds a device in the United States for producing power 
under lowhead conditions. The device resembles a series of Venetian blinds 
(hydrofoils) connected to an endless chain over a drum and shaft. The lift 
translator is available in sizes from 1 kW to 5 000 kW. Ossberger turbines 
(cross-flow) manufactured in West Germany are available for heads ranging 
from 1 metre to 200 metres (3 to 660 feet). The highest output per unit is 
about 1 000 kW. While not producing turbines at its own facilities, 
General Electric Company has arranged for Hitachi, a Japanese firm, to 
supply turbines for its generators. Although other American firms can 
supply hydraulic turbines in the 500 kW to 3000 kW range, the turbines used 
in new facilities would most probably be manufactured in Sweden, Canada, 
Switzerland, Norway, Austria, France, China, or Japan. 

The^ principal characteristic of any hydroelectric facility is the com- 
bination of head and streamflow that is specific to its site. The head 
available at the site usually dictates the type of turbine to be used, and 
streamflow is an important factor in determining its capacity. The most 
efficient design for a particular hydroelectric site is one designed for 
the site's conditions. Standardized turbines can save time and manufactur- 
ing costs, but a hydraulic turbine operates most efficiently over a narrow 
range of operating conditions, and outside of that range, the efficiency of 
the installation decreases. 

There are two general types of hydraulic turbines: the impulse 
turbine which has one or more jets that discharge water onto the buckets of 
a runner, and the reaction turbine, which is submerged in the streamflow 
and can be either a Francis type (mixed water flow) or propeller type 
(axial water flow). Both Francis and propeller turbines may be mounted 
horizontally or vertically. Propeller turbines can also be supplied with 
either fixed or variable pitch blades (the variable pitch propeller type is 
sometimes referred to as a Kaplan turbine). 

Impulse turbines may have some application for small hydroelectric 
installations with very high heads, but for comparable head and capacity, 
the reaction turbine generally costs less to manufacture. More information 
on turbines is given in Appendix I. 

Environmental Issues 

Environmental degradation, a principal concern with most energy devel- 

3—82256 



opment projects, is generally not a serious problem with the installation 
of small hydroelectric facilities at existing dams, canals, or pipelines. 
Since these hydraulic structures are already in place, and the small hydro- 
electric units are relatively minor additions to them, only minimal 
environmental impacts occur. A potential impact on the environment can 
usually be avoided by thoughtful design and construction. 

In a few cases where the impacts from secondary activities may have 
some significance, the impacts should be considered, case-by-case, separate 
from any impact the project itself might have. Construction of the proj- 
ect, for example, might generate dust and noise, increase local traffic 
erosion, silting, and turbidity in waterways, and remove vegetation. Any 
serious threat to the environment could be minimized by scheduling con- 
struction to avoid certain critical seasons and by exercising care. 

Operation of the facility could also have some impact. The operation 
of generators could increase noise levels and increase minor emissions of 
ozone, but existing energy dissipaters at many facilities are often noisier 
than the turbines and generators together. 

Various forms of wildlife could be affected by hydroelectric develop- 
ment. If the flow regime is changed this can affect fish. But turbine/ 
generators can be installed without altering the flow pattern. Although 
turbines are generally less harmful to fish than energy dissipaters, fish 
can be injured or killed by passage through turbines. The Endangered 
Species Act requires the Federal Energy Regulatory Commission (FERC) to 
assure that the development of any site will not interfere with or destroy 
endangered species. 

FERC has simplified licensing procedures, thereby greatly reducing the 
time required to process applications (Appendix F) . Site developers, how- 
ever, will have to comply with the California Environmental Quality Act 
(CEQA) and obtain several federal, state, and local approvals. The 
environmental assessment and approval process will require a minimum of one 
year (Chapter IV, Figure 13). In general, small hydroelectric recovery 
facilities can be installed and begin service within 30 to 36 months, as 
compared with the 10 to 15 years often necessary for major projects at new 
sites. 

The overall impact of small hydroelectric development would be bene- 
ficial. Development can be combined with various fish and wildlife proj- 
ects to create improved access for fishing, boating, and other recreational 
activities. Since hydroelectric power displaces power generated by 
nonrenewable resources, it conserves natural resources and reduces the need 
for more destructive activities such as mining and drilling. 

Small hydroelectric development will contribute significantly to the 
expansion of our nation's energy resources in an environmentally respon- 
sible manner. 

Economic Issues 



The lack of a ready market for power generated by small hydroelectric 
facilities significantly deterred development prior to the enactment of the 



Public Utility Regulatory Policies Act (PURPA) by Congress in 1978. PURPA 
and the policy of the California Public Utilities Commission (CPUC) created 
a market for this power by requiring electric utilities to purchase power 
from small power production facilities including hydroelectric projects at 
an "avoided cost." Basically, PURPA guarantees a market for power from 
small hydroelectric generation at a rate equal to the cost for the utility 
to generate the power itself or purchase the power from another source. In 
purchasing this power, the utility can thereby avoid having to produce or 
purchase the power. This avoided-cost pricing is discussed in Chapter II. 

Generally, it will take about 24 months to prepare preliminary feasi- 
bility study, obtain state and local approvals, and a FERC license. This 
period accounts for about two-thirds of a project's development schedule, 
and 20 percent of the total project cost. Title IV of PURPA promotes the 
development of potential facilities by providing loans for the necessary 
feasiblity studies and license applications — if the project is not 




Stab Creek Dam^ on the South Fork of the American 
River in El Dorado County, is owned by the Sacra- 
mento Municipal Utility District. A 400-kilowatt 
hydroelectric power plant at this site could gen- 
erate 3.0 million kilomtthours of electricity 
annually. This amount of energy would supply the 
annual electrical residential needs of 1,400 people. 
(Photo by DWR Division of Safety of Dams) 



feasible, the debt can be forgiven. The financing of projects is discussed 
more fully in Appendix H. 

Small hydroelectric development can have a socioeconomic effect as 
well. A number of temporary jobs are created during the construction of a 
project. Afterwards, permanent jobs are created for workers who must 
maintain and operate the facility. 

These projects provide excellent opportunities for training and 
employing the unemployed. The Comprehensive Employment and Training Act 
(CETA) provides federal funds for establishing hydroelectric power redevel- 
opment projects that will employ and train unemployed youths. 

Finally, small hydroelectric development will lessen the nation's 
balance-of-payments deficit by reducing oil imports; this, in turn, will 
reduce inflationary pressures. Besides decreasing the country's dependence 
on imported energy supplies, small hydroelectric facilities can allow 
individual communities to become more self-reliant in the production of 
energy. This dispersion of power-generating facilities will be most bene- 
fical to our nation's goal for energy independence and security. 

Retrofitting Problems and Their Solution 

Each potential small hydroelectric facility differs in the technical 
characteristics of the head and flow needed to produce p)ower; they can also 
differ because of the intended uses of the existing hydraulic structure. 
These uses include flood control, irrigation, and domestic water supply. 

Flood control dams use storage space in their reservoirs to absorb 
flood flows; releases from these reservoirs tend to be large and short 
lived. In a single-purpose flood control project, only minimal flows are 
released downstream for irrigation and in-stream uses during most of the 
year. The heavy flows released for short periods during flood control can- 
not be used economically to produce hydroelectric power. Flood control and 
power generation could be coordinated to use reservoir storage capacity 
more efficiently through agreements with the operators of the facility. 

The original designs of many flood control facilities did not provide 
for the tunnels, conduits, or waterways necessary for hydroelectric gener- 
ation. The problems this creates must be studied on a case-by-case basis. 

Irrigation dams are designed to conserve winter and spring runoff for 
release later during the summer. Generally, irrigation releases are larg- 
est from May through July and taper off from August through October, 
depending on the amount of storage available. Irrigation facilities are 
particularly suited to being retrofitted for hydroelectric generation 
because the heads and flows are significant and the major releases corres- 
pond with peak summer demand for electric power. In many cases, the 
installation of hydroelectric facilities at irrigation dams requires only 
minor alterations to the existing facility and its operation. 

Water distribution systems use pipelines to transport water from one 
place to another. The cost usually limits the size of pipe used in most 
cases. The limited power head that does exist is often further reduced by 



10 



the friction of the water flowing in the pipes. Irrigation and municipal 
pipelines carry heavier flows during summer months; therefore, the 
hydraulic head available for the generation of electric power can be lower 
during the season when peak demand for electrical energy occurs. 

Pipelines are often constructed of sections of precast concrete and 
serve as enclosed waterways. This type of conduit cannot be pressurized 
for use as a penstock for carrying the water to a power plant. 

The addition of hydroelectric power generation capacity at existing 
hydraulic structures must be compatible with the existing operation of the 
facility. At a flood control dam for example, if the existing outlet con- 
duit is to be used as a penstock, modification must be accomplished without 
restricting full-flood flow releases. The existing outlet works and speci- 
fic site conditions will determine how this might be accomplished. 

For irrigation dams, the additional hydroelectric generation unit 
itself can be the by-pass around the existing outlet valve that controls 
the irrigation releases. With an irrigation canal, sufficient hydraulic 
capacity must be available at the site to allow the full canal flow to pass 
if an outage of the hydroelectric units occurs during the irrigation 
season. 

Hydraulic turbines can be operated over a range of about 50 to 
115 percent of the rated flows and over a range of about 50 to 150 percent 
of the rated head. For some sites where large variations occur, this 
equipment limitation can restrict the amount of electrical energy actually 
generated to less than the potential generation calculated for the 
facility. 

Physical and Hydrologic Requirements 

The amount of electrical energy that can be produced annually is the 
single most important factor in determining the cost effectiveness of 
developing hydroelectric power generation at an existing facility. The 
amount of generation is related directly to how much water is available, 
for how long, and under what hydraulic head. 

The physical layout of an existing structure must be evaluated first. 
The data that must be obtained include the physical dimensions of the dam, 
canal, or pipeline; maximum and minimum hydraulic heads; tailwater level; 
rating curves for outlets and pipelines; relationships between the storage 
capacity of the reservoir and its elevation; and other operational criteria 
such as flood control restrictions on the reservoir, the amount and dura- 
tion of flows from the facility, and the minimum flow requirements for 
instream uses. 

Once the physical parameters of a facility are known, hydrologic data 
must be obtained before the average annual electrical generation can be 
calculated. These data include determining the drainage area; average 
daily or monthly flows over a ten- to fifty-year period; flow duration 
curves, conduit and outlet rating curves, effective hydraulic head-duration 
data; evaporation and seepage losses; and minimum instream flow 
requirements . 



11 



Daily flow data can be used to construct a flow-duration curve from 
which the facility's capacity and energy potential can be determined, and 
the annual electrical generation can be estimated. At most facilities, 
flow records have been kept since the facility was built and are available 
from the owner. In a few cases where these records are not available, 
records can be obtained from stream gaging stations and reservoir water 
recorders near the specific site. Some of these records are also available 
through various government agencies. The U. S. Geological Survey publishes 
continuous flow data on major streams and rivers; other agencies such as 
the U. S. Army Corps of Engineers, the Water and Power Resources Service, 
and the Soil Conservation Service also maintain stream flow records. This 
flow data, along with data published by various state agencies, usually can 
be found in libraries maintained by universities, by the state, or by vari- 
ous federal agencies. 

Status of Facility Development 

The progress and status of small hydroelectric projects are summarized in 
Tables 1 and 2. Out of 285 potential projects, 80 facilities — 
representing about 355 MW of the total installed capacity of 510 MW 
(70 percent) — have been completed, are under construction, or are in some 
other stage of development. 

In addition to the FERC permit and license applications the number of 
sites being considered for development are also indicated by the number of 
U. S. Department of Energy (DOE) loan applications, and California Energy 
Commission (CEC) grant applications. Table 3 lists the applications for 
DOE licensing and feasibility loans, and Table 4 lists the feasibility 
studies co-funded by the CEC. 



Table 1. Summary of the Status of Small Hydroelectric Projects at Existing 
Facilities 



Status (January 1981) 



Number 
of Facilities 



Capacity 
(kW) 



Energy 
(GWh/yr) 



Construction Complete 

Under Construction 

FERC License or Exemption Issued 

Applications Filed for FERC License 
or Exemption 

FERC Preliminary Permits Issued 

Applications Filed for FERC 
Preliminary Permits 

TOTAL 



8 


31 


200 


162 


5 


34 


600 


223 


13 


75 


800 


311 


4 


19 


530 


69 


31 


125 


785 


520 


19 


68 


555 


295 


80 


355 


470 


1 580 



12 



Table 2. Detailed Analysis of the Status of Small Hydroelectric Projects at Existing 
Faci I ities 



Owner/Project Name 



Capacity 
(kW) 



Energy 
(GWh/yr) 



CONSTRUCTION COMPLETE 

California Department of Water Resources 
Del Val le No. 1 



0.04 



Date 
comp leted 



10/80 



The Metropolitan Water District of Southern California 
Footh i I I Feeder 
Greg Avenue 
Lake Mathews 



9 100 


61 .3 


10/80 


1 000 


4.5 


6/80 


4 900 


18.6 


8/80 



Nevada Irrigation District 
Ro I 11 ns Dam 



12 000 



60.0 



6/80 



Richvale Irrigation District 
Richvale Canal 



100 



0.3 



8/80 



Turlock Irrigation District 
Turlock Main Canal Drop No. 1 
Turlock Main Canal Drop No. 9 



3 300 
1 100 



12.2 
4.7 



7/80 
10/79 



TOTAL 



31 200 



161 .6 



UNDER CONSTRUCTION 



Scheduled 

comp let ion 

date 



Pacific Gas and Electric Company 
Volta No. 2 Powerhouse 



1 000 



5.0 



1981 



The Metropolitan Water District of Southern California 
San Dimas 
Sepulveda Canyon 
Venice 
Yorba Linda Feeder 



9 900 


68.2 


2/81 


8 600 


56.2 


9/81 


10 000 


60.0 


12/81 


5 100 


33.5 


6/81 



TOTAL 

FERC LICENSE OR EXEMPTION ISSUED 

California Department of Water Resources 
Cottonwood No. 1 
Thermalito Afterbay River Outlet 

Merced Irrigation District 
Canal Creek 

Escaladian Drop (Canal) 
Fairfield Drop (Canal ) 
Richard B. Parker (on Main Canal) 

Orovl I le-Wyandotte Irrigation District 
Sly Creek Dam 

Sacramento Municipal Utility District 
Slab Creek 



34 600 



222.9 



17 


000 


13 


000 




900 




300 


1 


000 


2 


800 



13 200 



400 





Date issued 


115.0 


3/22/78 


43.0 


9/30/80 


3.3 


11/10/80 


0.8 


11/10/80 


2.8 


11/10/80 


9.2 


8/18/80 


48.2 


12/11/80 



3.0 



9/1 0/80 



13 



Table 2. Detailed Analysis of the Status of Small Hydroelectric Projects at Existing 
Facilities (Continued) 



Owner /Project Name 



Capacity 
(kW) 



Energy 
(GWh/yr) 



FERC LICENSE CR EXEMPTION ISSUED (Continued) 

South San Joaquin Irrigation District 
Frankenheimer Drop (Canal) 
Woodward Dam 

Turlock Irrigation District 
Turtock Main Canal Drop No. 6 
Upper Dawson Project 







Date Issued 


4 700 


18.7 


11/10/80 


2 300 


6.9 


8/18/80 


200 


0.8 


1/02/81 


4 000 


15.9 


11/10/80 



U.S. Water and Power Resources Service 
Lake Berryessa (Montecel lo Dam) 



16 000 



43.0 



1/29/81 



TOTAL 



75 800 



310.6 



APPLICATIONS FILED FOR FERC LICENSE OR EXEMPTION 



California Department of Water Resource 
Antelope Dam 
Casta ic Outlet 
Cottonwood No. 2 
Lake Davis (Grizzly Valley Dam) 
Del Val le No. 2 
Frenchman Dam 
Las F lores Turnout 
MoJ ave Siphon No. 1 
MoJ ave Siphon No. 2 
Palermo Outlet 
Pyramid Outlet 
Thermalito Diversion Dam 



1/ 



(Silverwood Lake Inlet) 
(Silver wood Lake Inlet) 







Scheduled 






completion 






date 


450 


1.4 


3/85 


275 


1.4 


3/84 


2 000 


90.0 


7/88 


500 


1.5 


1/85 


400 


1.1 


7/85 


450 


1.0 


9/84 


200 


0.7 


9/85 


5 000 


42.4 


7/83 


5 000 


42.4 


7/88 


400 


2.0 


1/84 


1 000 


4.0 


7/84 


3 000 


23.0 


9/83 



East Bay Municipal Utility District 
Camanche Dam 



10 680 



35.0 



1983 



Placer County Water Agency 
He I I Hole Dam 



550 



3.0 



1982 



Santa Barbara, City of 
Gibraltar Dam 



1 500 



4.0 



South Sutter Water District 
Camp Far West Dam 



6 800 



26.9 



TOTAL 



19 530 



68.9 



1/ Except for Cottonwood No. 2 and MoJ ave Siphon No. 
projects are scheduled to be filed by July 1981. 



1, applications for alt Department's 



14 



Table 2. Detailed Analysis of the Status of Small Hydroelectric Projects at Existing 
Faci I Itles (Continued) 



Ow ner /Project Name 



Capacity Energy 
(kW) (GWh/yr) 



Date 



FERC PRELIMINARY PERMITS ISSUED 



Issued to 



Anderson-Cottonwood I.D. 
Lal^e Redding 

Browns Valley Irrigation District 
Harding Canal 
Merle Collins Reservoir 
(Virginia Ranch Dam) 

Flat Water Ditch Company 
Saeltzer Dam 

Humbolt Bay M.W.D. 
Ruth Reservoir 

(R.W. Matthews Dam) 



City of Redding 

Owner 
Owner 

City of Redding 
Owner 



14 000 

1 900 
600 

875 
4 000 



50.0 

6.6 

5.6 

6.5 
14.2 



3/19/79 

7/22/80 
7/22/80 

2/27/81 
1/16/81 



Monterey County FC&WCD 
San Antonio Dam 



Owner 



6 000 



26.0 



6/21/79 



Nevada Irrigation District 
Lake Comb I e 

Oakdale and South San Joaquin I.D. 
Sand Bar Project 

San Bernardino Valley MWD 
Lytle Creek Turnout 
Santa Ana Low Turnout 
Sweetwater Turnout 
Waterman Canyon Turnout 

Siskiyou County FC&WCD 
Lake Siskiyou 
(Box Canyon Dam) 

Southern California Edison 
Paoha Project 

U.S. Army Corps of Engineers 
Black Butte Dam 
Hens ley Lake (Hidden Dam) 
H.V. Eastman Lake 

(Buchanan Dam) 
Lake Mendocino (Coyote Dam) 
New Hogan Dam 
Success Dam 



Owner 



Owner 



Owner 
Owner 
Owner 
Owner 



Owner 



Joseph M. Keating 



1 000 



12 000 



4 000 



500 



City of Santa Clara 5 000 

Madera Irrigation DIst. 1 300 

Madera Irrigation DIst. 3 000 

City of Uklah 4 000 

Calaveras Co. W.D. 2 000 

Lower Tule River Irrig. DIst. 4 000 



4.0 



70.0 



20.0 



25.0 
4.0 
9.0 

10.0 

8.0 

12.0 



3/26/79 



5/07/80 



1 300 


8.0 


1 0/29/80 


1 400 


4.0 


10/29/80 


900 


2.0 


10/29/80 


4 000 


7.0 


10/29/80 



1/01/79 



1.0 11/14/80 



10/14/80 
9/10/80 
9/1 0/80 

8/02/79 

1 1 /06/79 

9/04/80 



U.S. Forest Service 
Hume Lake (Dam) 

U.S. Water and Power Resources Services 
Boca Creek Dam 
Folsom Lake Pipeline 



Lewis Evans 



1 050 



4.6 10/14/80 



Truckee-Donner PUD 1 500 7.0 4/29/80 

San Juan Suburban Water DIst. 500 2.4 10/10/80 



4—82256 



15 



Table 2. Detailed Analysis of the Status of Small Hydroelectric Projects at Existing 
Fad lltles (Continued) 



Owner /Project Name 



Capacity Energy 

(kW) (GWh/yr) Date 



FERC PRELIMINARY PERMITS ISSUED 
(Continued) 



Issued to 



U.S. Water and Power Resources Services (Continued) 
Madera Canal 

Station 980+65 

Station 1064+67 

Station 1910+60 
Mlllerton Lake (Friant Dam) 
Prosser Creek Dam 
Red Bluff Diversion Dam 
Stony Gorge Dam 
Whiskeytown Dam 

TOTAL 



Madera Irrigation DIst. 
Madera Irrigation DIst. 
Madera Irrigation DIst. 
Terra Bella Irrigation DIst. 
Truckee-Donner PUD 
City of Redding 
City of Santa Clara 
City of Redding 



1 750 


5.5 


9/04/80 


560 


1.9 


9/04/80 


650 


2.6 


9/04/80 


23 000 


100.0 


5/15/80 


1 000 


3.5 


4/29/80 


14 000 


70.0 


5/08/80 


6 000 


18.0 


10/10/80 


4 000 


12.5 


3/25/80 


125 785 


520.9 





APPLICATIONS FILED for FERC 
PRELIMINARY PERMIT 



Edward S. Cruz and William L. Beavers 
Cottonwood Canyon and 
Lone Tree Creek 



App I leant 



City of Bakersfleld and Kern Delta W.D. 
Beards ley Canal 

Headworks Structure Owner 

Beardsley Diversion 

Structure Owner 

Rocky Point Diversion 

(Carrier Canal Project) Owner 



Owner 



200 
800 
660 

800 



3.0 11/05/80 
0.8 11/05/80 
2.5 11/05/80 



3.7 



1/14/81 



George Costa 
Trinity Tunnel 
(Del Loma) 



Hydro Development, Inc. 



600 



4.5 



11/25/80 



Oakdale and South San Joaquin I .0. 
Goodw I n Dam 



Owner 



4 920 



20.8 



1 0/09/80 



Pacific Gas and Electric Company 
Lake Plllsbury (Scott Dam) 

Redding, City of 
Soeltzer Dam 



U.S. Army Corps of Engineers 
Isabel la Datn— 



City of Uklah 



Owner 



California Department 

of Water Resources 
Sequoia Energy Corporation 
North Kern Water Storage 
District 



5 000 



875 



15.0 



6.5 



12/15/80 



1 0/29/80 



8 000 


18.5 


6/16/80 


2 300 


11.5 


7/11/80 


8 000 


17.0 


10/02/80 



\J Competing applications. 

16 



Table 2. Detailed Analysis of the Status of Small Hydroelectric Projects at Existing 
Facilities (Continued) 



Owner /Project Name 



Capacity Energy 

<kW) <GWh/yr) Date 



APPLICATIONS FILED for FERC (Continued) 

PRELIMINARY PERMIT Applicant 



U.S. Army Ck>rps of Engineers (Continued) 
Lake Clementine— 
(North Fork Dam) 



Lake Kaweah 
(Terminus Dam) 



1/ 



Warm Springs Project— 

U.S. Forest Service 
Lost Creek Project 



City of Redding 

City of McFarland and 

Western Renewable 

Resources, Inc. 
City of Santa Clara 

Kaweah Delta Water 
Conservation District 

City of Uklah 
Sonoma County W.D. 



Floyd N. BIdwell 



12 000 


63.5 


11/12/80 


11 000 


60.0 


7/17/80 


12 000 


60.0 


2/23/81 


9 500 


30.2 


1 /08/81 


3 000 


15.0 


5/27/80 


3 000 


15.0 


8/25/80 


1 800 


10.0 


12/15/80 



United Water Conservation DIst. 
Lake PIru 

(Santa Fel Ida Dam) 



Fluid Energy Systems 



3 600 



7.8 



9/16/80 



U.S. Water and Power Resources Service 
East Park Dam- 



New Siphon Drop— 
(Yuma Project) 
Palo Verde Diversion 
Sly Park Dan*!/ 



Stampede Dam- 



City of Santa Clara 900 2.2 9/29/80 
Or land Unit Water 

Users Association 1 600 4.0 1/08/81 

Western Water Power, Inc. 1 400 11.3 10/03/80 

Enagenlcs 4 040 21.2 1/09/81 

Mitchell Energy Company 8 700 53.0 1/12/81 
Cont I nenta I Hy dro 

Coorporatlon 570 2.1 12/09/80 
El Dorado Irrigation 

District 800 3.0 12/22/80 
American Hydroelectric 

Development Corporation 3 000 16.0 1/14/81 

Western Water Power, Inc. 1 800 13.2 1/06/81 



Yolo County Flood Control and Water 
Cksnservatlon District 

Clear Lake Impounding Dam 

TOTAL 



Owner 



2 000 7.5 1/27/81 

68 555 294.8 



1/ Competing applications. 



17 



Table 3. U. S. Department of Energy Feasibility and Licensing Loans 



Application No. Project 



Owner /Operator 



Date Rec'd 



Feasibility Loans 
F09001-'' 



F09002 



1/ 



F09003^^ 



F09004- 



F09005i'' 



F09006i-^ 



F09007-'' 



Fresno Main 
Canal 



New Hogan Dam 



Jackson Meadows 
Bowman Dam 



Combie Dam 



Lake Siskiyou 



San Antonio Dam 



Ruth Lake 



Fresno Irrigation District 8/31/79 
1568 North Millbrook Ave. 
Fresno, CA 93703 

Calaveras County 9/26/79 

Water Department 
427 East Street 
San Andreas, CA 95249 

Nevada Irrigation District 10/09/79 

P. 0. Box 1019 

Grass Valley, CA 95945 

Nevada Irrigation District 10/09/79 
(see above) 

Siskiyou County 10/12/79 

Flood Control Department 
305 Butte Street 
Yreka, CA 96097 

Monterey County 10/25/79 

Flood Control Department 
P. 0. Box 930 
Salinas, CA 93902 

Humboldt Bay 11/28/79 

Municipal Water District 
828 Seventh Street 
Eureka, CA 95501 



F09008 



F09009^' 



F09010^^ 



Semitropic 
Intake Canal 



Lyons Dam 



Barrett Dam 



Semitropic Water 

Storage District 
1340 F Street 
Wasco, CA 93280 

Tuolumne County 

Water District No. 
53 W. Bradford 
Sonora, CA 95370 

City of San Diego 

202 C Street 

San Diego, CA 92101 



1/12/80 



1/25/80 



2/03/80 



\_/ Loan approved 
2/ Loan rejected 



18 



Table 3. U.S. Department of Energy Feasibility and 
Licensing Loans (Continued) 



Application No. Project 



Owner/Operator 



Date Rec'd 



2/ 
F09011- 



F09012- 



1/ 



2/ 
F09013^' 



F09014i^ 



Fogois^'^ 



F09016^'' 



F 090 17-^ 



F0901&^^ 



F09019^'' 



F09023 



Sutherland Dam 



Madera Canal 



Hume Lake Dam 



Virginia Ranch 
Dam 



Hidden Dam 



Buchanan Dam 



Whitewater River 



Black Butte Dam 



Stony Gorge Dam 



Stumpy Meadows 
Reservoir 



City of San Diego 2/03/80 

202 C Street 

San Diego, CA 92101 

Madera Irrigation District 2/11/80 
12152 Road 28 1/4 
Madera, CA 93637 

Lewis Evans 3/03/80 

P. 0. Box 820 

Kings Canyon National Park 

CA 93633 

Browns Valley Irrigation 3/19/80 

District 
P. 0. Box 6 
Browns Valley, CA 95918 

Madera Irrigation District 4/10/80 
(see above) 

Madera Irrigation District 4/25/80 
(see above) 

Culver Nichols 5/08/80 

111 W. El Alameda 

P. 0. Box 580 

Palm Springs, CA 92262 

City of Santa Clara 5/12/80 

1500 Warburton Ave. 
Santa Clara, CA 95050 

City of Santa Clara 5/21/80 

(see above) 

Georgetown Divide 9/29/80 

Public Utility District 
P. 0. Box 338 
Georgetown, CA 95634 



^/ Loan approved 
2/ Loan rejected 



19 



Table 3. U. S. Department of Energy Feasibility and 
Licensing Loans (Continued) 



Application No. Project 



Owner /Opera tor 



Date Rec'd 



F09024 



Carrier Power 
Project 



City of Bakersfield 
1501 Truxton Ave 
Bakersfield, CA 93301 



11/25/80 



F09025 



Concow Project 



Thermal ito and Table 
Mountain Irrigation 
Districts 
710 Grand Avenue 
Oroville, CA 95965 



12/03/80 



F09026 



Scotts Flat 
Dam 



Nevada Irrigation District 12/08/80 

P. 0. Box 1019 

Grass Valley, CA 95945 



F09027 



English Meadows 
Dam 



Nevada Irrigation District 12/08/80 
(see above) 



F09028 



Lundy Reservoir 



Joseph M. Keating 
Keating Associates 
847 Pacific Street 
Placerville, CA 95667 



12/18/80 



Licensing Loans 
L09001- 



L09002 



1/ 



Lake Mendocino 



Friant Dam 



City of Ukiah 11/02/79 

203 S. School Street 
Ukiah, CA 95982 

Friant Power Authority 11/30/79 
Terra Bella Irrigation 

District 
2479 Ave. 95 
Terra Bella, CA 93270 



L09003 



New Hogan Dam 



Calaveras County 
Water District 
427 East St. Charles 
San Andreas, CA 95249 



10/07/80 



L09004 



Lake Siskiyou 



Siskiyou County 10/21/80 

Department of Public Works 
305 Butte Street 
Yreka, CA 96097 



L09005 



Lake Combie Nevada Irrigation District 12/08/80 

P. 0. Box 1019 
Grass Valley, CA 95945 



\_l Loan approved 
2/ Loan rejected 



20 



Table 4. California Energy Commission Feasibility Study Grants 



Owner/Developer 



Site 



Amador County Water Agency 

Calleguas Municipal Water District 

Chowchilla Water District 

El Dorado Irrigation District 

El Segundo, City of 

Irvine Ranch Water District 

Lockheed Missiles & Space Co., Inc. 
North Tahoe Public Utility District 
Orange Cove Irrigation District 
Paradise Irrigation District 
Redlands, City of 

San Bernardino Valley 

Municipal Water District 

San Diego County Water Authority 

San Gabriel Valley MWD 

San Juan Suburban Water District 



Truckee-Donner Public 
Utility District 

Whitewater Canyon Mutual Water Co. 



Central Amador Water Project 

Conejo Pump Station 

Madera Canal Station 980+65 (WPRS) 

Water Distribution System 

Pressure Reducing Station 

Irvine Lake Pipeline 
(Rattlesnake Reservoir) 

Big Creek Powerhouse Rehabilitation 

Griff Creek-Mt . Baldy Springs Project 

Sand Creek Check 

Paradise Reservoir 

Highland Avenue Pumping Plant 
Redlands Water Treatment Plant 

Santa Ana Low Turnout 
Sweetwater Turnout 

Treatment Plants & Tunnel 

Devil Canyon-Azusa Pipeline 

Treatment Plant to Distribution 
System 

Boca Dam (WPRS) 

Prosser Creek Dam (WPRS) 

Whitewater Canyon Irrigation System 



21 




Antelope Damj on Indicm Creek -in Plumas County j is owned by the 
California Department of Water Resources. A 450-kilowatt hydro- 
electric power plant at this site could generate 1.4 million 
kilowatthours of electricity annually. This amount of energy is 
equivalent to burning 2^400 barrels of oil in a fossil- fuel plant. 

(DWR photo 2759-7) 



22 



CHAPTER II 
THE PURCHASE OF SMALL HYDROELECTRIC POWER BY UTILITIES 



Historically, a producer of small hydroelectric power wishing to 
market the energy produced, faced three major obstacles. Utilities were 
often unwilling to purchase the energy or to pay a reasonable price. 
Secondly, some utilities charged unreasonably high rates for providing 
back-up or standby service to customers who produced and used some of their 
own power. Often, these utilities also heavily discounted the value of 
such generation when calculating dependable capacity and reserves, and 
charged high wheeling (transmission) costs. Lastly, a small power producer 
who sold generation to a utility also ran the risk of being classified as 
an electric utility and thus becoming subject to state and federal 
regulation. 

Until very recently, these obstacles discouraged the development of 
new small hydroelectric power facilities. Now, electric utilities are 
required to purchase the generation from small hydroelectric projects at a 
price equal to the costs that the utilities would incur producing the power 
themselves, or purchasing this amount of energy from other sources. A 
developer can, of course, use the energy generated for his own purposes 
without penalty. 

Pertinent Legislation 

The Public Utility Regulatory Policies Act of 1978 (PURPA) signifi- 
cantly changed the method for determining the value of energy generated by 
small power production facilities and cogeneration facilities, and also 
changed the requirements for electric interconnection and the wheeling of 
power produced by such facilities. The sections of PURPA which are parti- 
cularly pertinent to small hydroelectric projects are Sec. 201, which 
defines a qualifying facility; Sec. 210, which defines the rates at which a 
qualifying facility can sell its energy; and Title IV, which provides loans 
for conducting feasibility studies and for licensing. 

The impact of PURPA on the development of small hydroelectric 
generation is only now beginning to be felt. The Federal Energy Regulatory 
Commission (FERC) is in the process of establishing requirements and 
procedures that will filter down to the utilities and state regulatory 
agencies . 

California is ahead of most other states in implementing some of the 
policies established by PURPA. The California Public Utilities Commission 
(CPUC) investigated Pacific Gas and Electric Company's (PGandE) resource 
plan and its alternative plans, their ratemaking implications, and the 
options available with each plan (CPUC Order Instituting Investigation 
No. 26, 011-26). The CPUC ordered PGandE to publish cogeneration rates 
based on its avoided cost and authorized the utility to purchase power from 
cogeneration facilities at those rates (CPUC Decision 91109, December 19, 
1979). On February 4, 1980, PGandE announced that it would purchase energy 
from cogenerators and small power producers. The CPUC also extended the 
avoided-cost principle of Decision 91109 to the other CPUC-regulated 
electric utilities in California (CPUC Resolution E-1872, March 4, 1980). 



5—82256 



23 



FIGURE 3 



(0 

c 

CO 



E 

CO 
V 

o5 

c 
o 



LU 
(0 

o 



(0 

LU 
eO 
O 
Q. 

CO 

c 
o 

CO 

o 

c 

o 

"O 



O 

o 

(0 

o 
O 

CO 
C3) 




o 
CO 

CT> 



O 



CO 

a: 
< 

LU 

>■ 



in 

CO 



o 
<o 



m o 

COST: DOLLARS/BARREL 



24 



These include Southern California Edison (SCE), San Diego Gas and Electric 
(SDG&E), Pacific Power and Light (PP&L), Sierra Pacific Power, and CP 
National . 

All of these electric utilities were directed to publish interim 
offers to buy electricity from cogenerators and small power producers 
pending the completion of CPUC rulemaking in compliance with PURPA. 
Standard price offers specific to small hydroelectric facilities (under 
100 kW and over 100 kW) have been developed by PGandE ; SCE, SDG&E, CP 
National, PP&L, and Sierra Pacific Power have developed similar price 
offers applicable to small hydroelectric power producers. The purchase of 
electricity from small hydroelectric producers by these utilities will be 
based on these price offers pending final implementation of PURPA by the 
CPUC. 

The CPUC instituted a generic proceeding (OIR-2) to implement PURPA. 
This order will establish standards governing the prices, terms, and 
conditions of the utilities' purchases of electric power from cogeneration 
and small power production facilities. Owners or developers of qualifying 
facilities (QF) can accept the standard offers now available or can nego- 
tiate an agreement with the utilities on some other basis. In addition, 
the CPUC requested utilities to vigorously pursue making agreements with 
small power producers. To facilitate this activity, while OIR-2 is in 
progress, the CPUC staff is encouraging utilities and the owners or 
developers of QFs to agree to modify their contracts to conform with any 
standards adopted in OIR-2. Summaries of the power-purchase agreements 
for PGandE, SCE, and SDG&E are included in Appendix G. 

Cost of Alternative Generation 

According to Section 210 of PURPA and the standard set forth by CPUC 
Decision 91109, the alternative generation from a small hydroelectric 
project can cost no more than the energy a utility would have to generate 
itself or purchase from another source. Since the utility can "avoid" 
producing this power by purchasing it, its cost is called the "avoided 
cost". The avoided-cost standard encourages the development of renewable 
resources, such as biomass, wood waste, refuse, and falling water, thus 
reducing our dependence on foreign oil. In California, and elsewhere, 
small hydroelectric projects will produce electrical energy that would 
otherwise be produced by oil-fired generating facilities. Thus, the 
avoided cost of energy will be related directly to the current and future 
cost of fossil fuel, primarily oil. 

Historical Costs of Energy . The cost of oil has increased dramatically 
from about $2 a barrel in the 1960s to about $26 by mid-1980. The average 
cost of oil burned to produce electricity at PGandE's six most-efficient 
steam-electric power plants from 1959 through 1979 is shown in Figure 3. 
The cost of electrical energy produced by these oil-fired steam plants has 
increased from about 0.4 cents per kWh in the early 1960s to 3 cents per 
kWh in 1979. 

Because of the rapidly rising price of crude oil and the time lag 
between purchase and actual use of this oil to generate electricity, the 
average annual cost may be misleadingly low. Thus, while the average cost 
of oil for electricity generation at PGandE's power plants during 1979 was 



25 



Hi 

cr 

< 
m 



oc 
< 

-I 
_i 
o 

Q 



W 
O 
O 



Figure 4 Cost of Oil Burned for Electric Generation 
Middletown Station - Hartford Electric Lighting Company 

Hartford, Connecticut 




J M M J S 

1977 



N J M M J S N 

1978 



JMMJSNJMMJ SN 

1979 1980 



26 




1% ^^ H| --^^ 

Indian Valley Dam, on a tributary of Cache Creek in Lake 
County, is owned by the Yolo County Flood Control and 
Water Conservation District. A 3 200-kilowatt hydro- 
electric power plant at this site could generate 7.2 
million kilowatthours of electricity per year. This 
amount of energy would supply the annual electrical 
residential needs of 3,400 people. 

(Photo by DWR Energy Division) 

calculated to be about $18.20 per barrel, th^ , actual cost during the last 
quarter of 1979 was about $21.50 per barre 



\y 



The world market price for oil has increased even more during the 
first half of 1980. In the second quarter of 1980, Saudi Arabia increased 
its oil price from $26 to $28 per barrel. Although other oil-producing 
countries charge even more, the Saudi Arabian price generally reflects the 
average cost of all oil burned in the United States to produce electrical 
energy. The increase to $28 per barrel will be partially reflected in the 
1980 cost of electrical energy, and fully reflected in the 1981 average 
cost. The actual cost of oil burned to generate electricity at a cycling 
steam-electric plant in the northeastern United States is comparable to the 
cost of oil used in California (Figure 4). 

Projected Energy Costs . Reasonable estimates of the future prices for oil 
must be obtained in order to calculate the benefits or losses of capital 
investment in small hydroelectric facilities. The future prices of energy 
have been estimated in this report using figures supplied by the California 
Energy Commission (CEC) and other knowledgeable sources. 

The CEC is conducting a continuing investigation into the cost and 
supply of fuels. In a comprehensive report, discussing supply availability 
and the projected costs of fuels,— the CEC staff stated, "Continuing 

1^1 Estimated from energy rates developed by PGandE as a result of CPUC 
~ Decision 91109. 

V Staff Draft Report. "Fuel Price and Supply Projections 1980-2000," 
California Energy Commission Publ. P102-79-014. November 1979. 



27 



international chaos indicates that any lessons to be learned from historic 
trends can be rapidly overshadowed by geopolitical shifts and [an] 
essentially complete disregard for free market forces. As the price and 
supply of oil to California [are] is shaped much more by world forces than 
by any internal dynamic[s] of supply and demand, the task of predicting our 
future oil availability/price is extremely difficult." 

Although California is the fourth largest producer of oil and gas in 
the United States, about two-thirds of the State's energy supplies are 
imported . 

The CEC report predicts substantial increases in the price of oil, 
because it is much less costly to increase oil- producing capacity in Saudi 
Arabia than to produce heavy crude oil in Venezuela or oil shale in 
Colorado. The average production cost in Saudi Arabia is probably less 
than $2 per barrel, while new Venezuelan oil would cost about $15 per 
barrel to produce; alternative fuels derived from coal would cost about $30 
to $35 per equivalent barrel of oil (in 1979 dollars). Thus, Middle 
Eastern producers would probably maintain price levels low enough to pre- 
clude stimulating the development of alternative sources oil production or 
of alternative fuels. 




Stony Gorge Dcm, on Stony Creek in Glenn County, is owned 
by the U. S. Water and Power Resources Service. A 6 000- 
kilowatt hydroelectric power plant at this site could gen- 
erate 18 million kilowatthours of electricity per year. 
This amount of energy is equivalent to burning ZO, 700 
barrels of oil in a fossil-fuel power plant. 

(Photo by Dm Northern District, Red Bluff) 



28 




Camanohe Dam^ on the Mokelumne River -in San Joaquin County, is 
owned by the East Bay Municipal Utility District. A 10 680- 
kilowatt hydroelectric power plant at this site could generate 
35 million kilowatthours of electricity annually. This amount 
of energy is equivalent to burning 69,700 barrels of oil in a 
fossil- fuel power plant. 

(East Bay Municipal Utility District Photo) 

The CEC ' s most likely scenario in projecting the future cost of oil 
assumes that oil producers will continue to demand large price increases 
over the near term, and that new oil production and alternative derived 
fuels will only be developed at a moderate pace. The CEC's projected 
prices for oil and the projected annual escalation rates for these prices 
are shown in Tables 5 and 6, respectively. 

Table 5. CEC's Projected Prices of Oil (1979 Dollars per Barrel) 



Type of Oil 



1980 



Year 



1985 



1990 



2000 



Crude Oil 

Distillate 

Residual Oil (0.5% Sulfur) 



20.00 27.50 31.80 37.70 
25.58 38.00 43.85 51.56 
22.87 35.82 42.00 49.67 



Table 6. Annual Escalation Rates of Oil Prices (Percentage) 















Years 




Type of Oil 


1981-85 


1986-90 


1990-2000 


Crude Oil 
Distillate 
Residual Oil 


(0. 


,5% 


Si 


jlfur) 


6.6 
8.2 
9.4 


3.0 
3.0 
3.2 


1.7 
1.9 
1.7 



29 



In order to assess the feasibility of a small hydroelectric project, 
the value of the energy generated during the early years of the project's 
operation must be determined. The economic benefits achieved during its 
first year of operation will likely increase in subsequent years due to 
increasing energy prices. Since the CEC ' s price projections were given in 
1979 dollars, it is necessary to escalate those projections to reflect 
future inflated dollars. Estimates of general inflation rates are needed 
to determine these future oil prices, but projections of general inflation 
rates for future years are difficult to make. 

It is logical to predict that the world price of oil will escalate as 
rapidly as the world economy can withstand it, until the price of oil 
approaches (but does not reach) the cost of producing synthetic fuels from 
coal, tar sands, and oil shale. If that level were reached, the price of 
oil would have to be competitive with that of alternative fuels. 

Assuming that the world economy — and the American economy in 
particular — can withstand an annual inflation rate of about 12 percent, it 
is only a matter of time until synthetic fuels and solar energy must be 
developed. If the development of synthetic fuels and solar energy were 
ignored, the United States would have to pay a premium price for energy, 
and thereby, would become noncompetitive in the world market. 

Given that synthetic fuels and solar electrical generation will be 
developed within five years, the logical scenario would show annual 
inflation rates of 15 percent in 1980, 12 percent in 1981 through 1985, 
8 percent in 1986 through 1990, and 6 percent thereafter. Based on this 
and using the CEC median-price projections for basline data, the estimated 
price of oil in future dollars is shown in Table 7. 



Table 7. Estimated Price of Oil (Future Dollars per Barrel) 



Year 



Type of Oil 1980 1985 1990 2000 



Crude 23 54 94 193 

Distillate 29 73 124 266 

Residual Oil (0.5% Sulfur) 26 69 117 247 



Residual Fuel Oil containing 0.5% sulfur is burned by PGandE to pro- 
duce electrical energy. The projected 15 percent price increase 1980 would 
result in a 1980 cost of about $26 per barrel to PGandE. This is 
consistent with CECs projection and with the $26 price established by Saudi 
Arabia in mid-1980. 



30 



Estimated Payments for Hydroelectric Generation 

The estimated payments for hydroelectric generation to be made by 
PGandE, SCE , and SDG&E are shown in Tables 8 and 9. The projections are 
based on estimated inflation and escalation rates, and the rates of 
proposed payments made by the utilities for hydroelectric generation in 
1980. Since the payments for hydroelectric generation are based on the 
avoided cost of oil, the estimated price of oil is also shown in these 
tables. The historical and projected costs of oil burned by PGandE to 
produce electrical energy are shown in Figure 5. 



Table 8. Projected Energy Rates for Sale of Small Hydroelectric 
Generation 



Year 



Oil Price 
Escalation 
Rate (%)i' 



Inflation 
Rate (%) 



Price of 

Oil 
($/bbl) 



Energy Rate (<t:/kWh) 



PGandE 



SCE 



SDG&E 



1980 



15 



26 



5.1 



4.6 



5.4 



1981 


9.4 


12 


31 


6.2 


5.6 


6.6 


1982 


9.4 


12 


38 


7.5 


6.8 


8.0 


1983 


9.4 


12 


47 


9.1 


8.3 


9.7 


1984 


9.4 


12 


57 


11.1 


10.1 


11.7 


1985 


9.4 


12 


69 


13.4 


12.2 


14.2 


1986 


3.2 


8 


77 


15.0 


13.6 


15.8 


1987 


3.2 


8 


85 


16.6 


15.1 


17.6 


1988 


3.2 


8 


95 


18.5 


16.8 


19.6 


1989 


3.2 


8 


106 


20.6 


18.7 


21.8 


1990 


3.2 


8 


117 


22.9 


20.8 


24.2 


1991 


1.7 


6 


127 


24.6 


22.4 


26.1 


1992 


1.7 


6 


136 


26.5 


24.1 


28.1 


1993 


1.7 


6 


147 


28.6 


26.0 


20.2 


1994 


1.7 


6 


158 


30.8 


28.0 


32.6 


1995 


1.7 


6 


170 


33.1 


30.1 


35.1 


1996 


1.7 


6 


184 


35.7 


32.5 


37.8 


1997 


1.7 


6 


198 


38.4 


35.0 


40.7 


1998 


1.7 


6 


213 


41.4 


37.7 


43.8 


1999 


1.7 


6 


229 


44.6 


40.6 


47.2 


2000 


1.7 


6 


247 


48.0 


43.7 


50.8 



1/California Energy Commission's Median Projection 



6—82256 



31 



Table 9. Capacity Payment Rates, by Utilities ( $/kilowatt-year ) 
Effective February 4, 1980. 





of Initial 






Term 


of Sales 


(yrs) 






Year 
















Operation 


1 


5 


10 


15 


20 


25 


30 




PGandE 


_ 


56 


62 


68 


73 


_ 


81 


1980 


SCE 


- 


29 


54 


70 


82 


- 


102 




SDG&E 


- 


- 


16 


27 


35 


40 


— 




PGandE 


- 


60 


66 


72 


77 


- 


85 


1981 


SCE 


- 


39 


64 


79 


93 


- 


114 




SDG&E 


- 


— 


22 


34 


43 


48 


— 




PGandE 


— 


63 


69 


75 


81 


- 


89 


1982 


SCE 


30 


51 


75 


90 


104 


- 


127 




SDG&E 


- 


8 


30 


43 


52 


59 


— 




PGandE 


60 


66 


73 


79 


85 


- 


94 


1983 


SCE 


32 


65 


87 


103 


118 


- 


143 




SDG&E 


- 


18 


41 


54 


64 


71 


— 




PGandE 


63 


69 


76 


83 


89 


- 


98 


1984 


SCE 


35 


82 


102 


117 


133 


- 


159 




SDG&E 


- 


30 


53 


67 


78 


86 


- 




PGandE 


66 


73 


80 


87 


93 


- 


103 


1985 


SCE 


- 


101 


118 


134 


151 


- 


180 




SDG&E 


— 


45 


68 


83 


95 


104 


" 




Scotts Flat Damj on Deer Creek in Nevada County, is owned by the 
Nevada Irrigation District. A 2 200-kilowatt hydro eleotr^a power 
plant at this site could generate 5.5 million kilowatthours of 
electricity annually. This amount of energy would supply the 
annual electrical residential needs of 2,600 people. 
(Photo by DWR Division of Safety of Dame) 



32 



FIGURE 5 



c 




o 








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o 


t9 




*- 


m^ 


c 


CO 


CO 


o 




'w 


0. 






o 


u 


« 


l_ 




♦< 


UJ 


u 




« 


^ 




o 


UJ 






_ 


E 


O 


CO 


<^ 


♦^ 


o 


CO 


♦« 


^^ 


CO 


C 


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0) 


o 


u 


Ol 

(S 


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^ 


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o 


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: 


•o 


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o 


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o 


Q. 


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0. 






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•a 


CD 


c 




9 




^^ 




(0 




O 








h> 




o 




♦* 




« 








z 





5 

Ik 



\ 

— % 

\ 
\ 
\ 
\ 
\- 

y 
\ 

V 

> 

X 

^ 



o 
o 

CM 





w 


o 


cr 


00 


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CT> 


III 




> 


■A 




1^ 




O) 





o 

o 



o 

IT) 



COST: DOLLARS/BARREL 



S3 



Figure 6 Selection and Evaluation Flow Chart 



Statewide Inventory ot E 


xisting Hydraulic 


Facilities 




DAMS CANALS PIPELINES 

(137] [533 C95} 
















' 




1 ' 




1 



Studied by DWR 



T 



Field Investigations 



D C P 

(23D C12] (143 



T 



Preliminary Feasibility 
Studies 



D C P 

(133 (93 (63 



Utility Payments for 
Hydroelectric Power 



Studied by Others 



Appraisals and Feasibility 
Studies 




-Wi 



Project Cost Information & 
Annual Cost Estimates 



] 



Evaluations 



Cost Effectiveness 




Questionnaire Responses 




34 



CHAPTER III 
SELECTION AND EVALUATION 



Hydraulic structures where hydroelectric facilities might be installed 
were identified through information obtained from (a) questionnaires dis- 
tributed by the Department, (b) the U.S. Army Corps of Engineers' National 
Hydroelectric Power Study, (c) local water agencies and districts, and (d) 
the state's electric utilities. The Department identified 285 sites which 
had a potential for small hydroelectric development. These sites repre- 
sented 510 000 kW of capacity and an annual output of 2.4 billion kWh of 
energy. The methodology for evaluating the cost effectiveness of each of 
the 285 sites is outlined in the Selection and Evaluation Flow Chart 
(Figure 6). 

Selection 

The facilities were divided into three groups based on the type of 
hydraulic structure: dam, canal, or pipeline. Each group was further 
divided into those facilities with installed capacities of 500 kW or 
greater and those with less than 500 kW of capacity. This was important 
for determining cost effectiveness since the cost of building a small power 
plant increases rapidly — on a dollar-per-kilowatt basis — as the installed 
capacity decreases below 500 kW. 

Since time and money were limited, it was impossible to study each of 
the 285 facilities first hand. The evaluations made in this study were 
based on three types of information: data from preliminary feasibility 
studies conducted by the Department at 28 representative sites; data from 




Ruth Reservoir (Robert W. Matthews Dam), on the Mad River in Trinity 
County, is owned by the Humboldt Bay Municipal Water District. A 
1 600-kilowatt hydroelectric power plant at this site could generate 
8.2 million kilowatthours of electricity per year. This is equiva- 
lent to burning 14,200 barrels of oil in a fossil-fuel power plant. 
(Photo by DWR Division of Safety of Dams) 



35 



feasibility or appraisal studies conducted by others at 42 additional 
sites; and data on the head and flow at 215 remaining sites as obtained in 
response to the Department's quest ionnaries . 

The Department conducted its studies in two phases consisting of field 
investigations and preliminary feasibility studies. Forty-nine sites were 
selected for initial field investigations. These sites represented the 
types of hydraulic structures found in California and contained examples 
from each of the six categories. The 49 facilities are listed in Table 10. 



Table 10. Field Investigations Conducted by the Department of 
Water Resources 



Site 



Owner 



1, 
2, 

3. 

4. 



6. 

7. 

8. 

9. 
10. 
11. 
12 
13. 
14. 
15. 
16. 
17. 

18. 

19, 

20. 
21. 
22. 
23. 
24. 

25. 

26. 

27, 



Anderson Flume Diversion- 



Parkview Station—' 



1/ 



1/ 



Harding Canal—' 

Merle Collins Reservoir- 

(Virginia Ranch Dam) 
Frenchman Dam—' 

Beardsley Diversion- 
Rocky Point Diversion— 
Glendale Distribution—' 
Alvarado Treatment Plant 
Miramar Treatment Plant 
Moccasin Reregulating Dam 
Mount Olivettel' 
Chowchilla Main Canal 
Fresno Main Canal 
Gould Weir Diversion Dam—' 
Del Loma Tunneli-^ 
Buckeye Conduit— 



1/ 



Stumpy Meadows Reservoir- 

(Mark Eds on Dam) 
Ruth Reservoir 

(Robert W. Matthews Dam) 
Alamo Drop 3A— ' 
No. 8 Headingl^ 
Tuberose Check 
Vail Headingl' 
Lake Amador— 

(Jackson Creek Dam) 
Pacoima Dam 

San Gabriel Dam 

West Coast Basin Barrier— 



Anderson-Cottonwood Irrigation 

District 
Anderson-Cottonwood Irrigation 

District 
Browns Valley Irrigation District 
Browns Valley Irrigation District 

California Department of Water 

Resources 
City of Bakersfield, et al . 
City of Bakersfield, et al . 
City of Glendale 
City of San Diego 
City of San Diego 
City and County of San Francisco 
City of Santa Monica 
Chowchilla Water District 
Fresno Irrigation District 
Fresno Irrigation District 
George Costa 
Georgetown Divide Public Utility 

District 
Georgetown Divide Public Utility 

District 
Humboldt Bay Municipal Water 

District 
Imperial Irrigation District 
Imperial Irrigation District 
Imperial Irrigation District 
Imperial Irrigation District 
Jackson Valley Irrigation 

District 
Los Angeles County Flood Control 

District 
Los Angeles County Flood Control 

District 
Los Angeles County Flood Control 

District 



Z6 



Table 10. Field Investigations Conducted by the Department of 
Water Resources (Continued) 



Site 



Owner 



28. Eastside Pipeline 

29. Lake Shastinai' 

(Shasta River Dam) 

30. Pumping Plant Lower- 



Si. 
32. 
33. 

34. 

35. 

36. 

37. 
38. 

39. 

40. 

41, 

42. 
43. 

44. 

45. 

46. 

47. 

48. 

49. 



Picay Pressure Break 

Lyons Dam 

San Vicente Reservoir 

(Pipeline) 
Sidney N. Peterson 

Treatment Plant 
Chesbro Dam—' 



Uvas Dam—' 



1/ 



Black Butte Dami-' 
Hensley Lake 

(Hidden Dam) 
H.V. Eastman Lake 

(Buchanan Dam) 
Lake Kaweah 



(Terminus Dam) 



/ 



Lemoncove Ditch— 

(At Terminus Dam) 
New Hogan Dam 
Ail-American Canal Drop 

No. 5 
Jenkinson Lake— 

(Sly Park Dam) 
North Portal Tecolote— 

Intake 
Stampede Dam 



1/ 



Sonoma Reservoir 
Clear Lake Impounding— 
Indian Valley Dam—' 



Lost Hills Water District 
Montague Water Conservation 

District 
Montague Water Conservation 

District 
Montecito County Water District 
Pacific Gas and Electric Company 
San Diego County Water Authority 

San Juan Suburban Water District 

South Santa Clara Valley Water 

Conservation District 
South Santa Clara Valley Water 

Conservation District 
U. S. Army Corps of Engineers 
U. S. Army Corps of Engineers 

U. S. Army Corps of Engineers 

U. S. Army Corps of Engineers 

U. S. Army Corps of Engineers 

U. S. Army Corps of Engineers 
U. S. Water and Power Resources 

Service 
U. S. Water and Power Resources 

Service 
Cachuma Operation and Maintenance 

Board 
U. S. Water and Power Resources 

Service 
Valley of the Moon County Water 

District 
Yolo County Flood Control and 

Water Conservation District 
Yolo County Flood Control and 

Water Conservation District 



1/ Included in the 28 representative sites whose preliminary 
feasibility studies are presented in Appendix C. 



37 



Field Investigations 

An on-site field study of each site was conducted to determine which 
sites were suitable for preliminary feasibility studies. During these 
inspections, the physical characteristics of the site were noted, including 
the amounts of head and flow, types of conduits and construction materials, 
the presence of canals and other adjoining waterways, and the characteris- 
tics of gates, valves, and energy dissipaters. The historical operational 
procedures and the primary purpose of the existing facility were also con- 
sidered. A record of past flows and releases was obtained for use in 
computing the potential energy output. Each study is discussed briefly in 
Appendix B. 

Some potential sites were unsuitable or impractical for development 
for various technical reasons. These included sites with (1) little or no 
effective head; (2) an inadequate combination of head and flow; (3) an 
adequate flow of limited duration; (4) concrete conduits that cannot be 
pressurized for use as penstocks; (5) a current use that is incompatible 
with hydroelectric generation; (6) serious environmental problems including 
those associated with development on a wild or scenic river or within a 
wilderness area; (7) a need for long transmission lines; or (8) hydraulic 
structures that are simply in poor physical condition. 




Lake Piltsbury (Scott Dean), or. the Eel River in Lake County, 
is owned by the Pacific Gas and Electric Company. A 2 800- 
kilowatt hydroelectric power plant at this site could gen- 
erate 10 million kilowatthours of electricity per year. This 
amount of energy would supply the annual electrical residen- 
tial needs of 2,400 people. 

(Photo by DWR Energy Division) 



38 




Richvale Canal Powerplant, on the Riohvale Canal in 
Butte County t is owned by the Riohvale Irrigation 
District. This 100-kiloioatt hydroelectric power 
plant, constructed in 1980, generates 0.4 million 
kilowatthours of electricity annually. This amount 
of energy will supply the annual electrical res- 
idential needs of 190 persons. 

(Photo by DWR Energy Division) 

Feasibility Studies 

If the on-site inspection showed a power project to be 
technically feasible, economic feasibility and cost effectiveness could 
then be assessed on the basis of known site-specific characteristics. Of 
the 49 representative sites, projects at 28 of the sites were found to be 
technically feasible. These sites were then subjected to preliminary 
feasibility studies which used uniform methods to evaluate the physical 
layout, to estimate the necessary construction costs, and to provide a 
common base on which to develop guidelines for assessing other potential 
sites . 

Guidelines 

Each hydroelectric project is distinct, since few sites have the same 
combinations of head and flow or the same physical features. The most 
efficient turbine-generator design is one engineered specifically for the 
head and flow conditions of a particular site. The foundation, structures, 
and waterways must also be designed individually. If studies of specific 
hydroelectric sites are extrapolated to other sites which have unknown 
local conditions, a degree of error will be built-in to the evaluation. 

Guidelines derived from a sampling of feasibility studies can be used 



39 



to make a general assessment of other sites where the head and approximate 
annual flows are known. The guidelines based on the calculated cost 
effectiveness of the 28 representative sites studied by the Department were 
extrapolated to the 257 other sites. The parameters used included 
(1) Design capacity, as determined by the head and flow; (2) Annual energy 
generation, as determined from head and water available for power 
production; (3) Capacity factor; (4) Estimated project cost; (5) Estimated 
annual cost of ownership and operation; and (6) Payments by utilities for 
hydroelectric generation. 

Design Capacity . The design capacity of a site is established by the 
physical features of the head and the flow of water. The design head is 
the net head after subtracting losses due to friction developed as the 
water flows to the turbine. However, since the known heads and flows at 
many potential sites are only approximations, the design head must be the 
estimated available head. The design flow, usually expressed in cubic feet 
per second (cfs) during a specific period of time such as a month, should 
be an average of more than three or four months. 



The estimated capacity of the unknown site (C, in kilowatts), is the 
product of head (H, in feet) and flow (F, in cubic feet per second) divided 
by a factor that represents the efficiency of the equipment and the 
efficiency of converting the energy of falling water into electric power; 
for estimating purposes, an efficiency factor of 14 can be used. This 
results in the equation: C = F x H/14 or kW = cfs x ft/14. A graph of 
head and flow data can be used to estimate the design capacity of a site 
(Figure 7) . 

Figure 7 Power Developed at Various Combinations of Head and Flow 



100 
1 80 

5 60 






40 


50 


60 


80 


100 


150 200 

Q 

Net Flow (els) 



400 500 600 800 1000 



40 



Project Cost . Among other things, the cost of constructing a hydroelectric 
project depends on local physical and geological features, and the length 
and size of the transmission lines required. The estimated cost of a 
particular facility is also affected by the design capacity. The estimated 
project costs for the 28 representative sites are shown in Figure 8 and are 
discussed in detail in Appendix C. 

In the range of 50 kW to 3200 kW of installed capacity, project costs 
vary from $1,700 to $6,000 per kW. Since the costs were estimated in 1980 
dollars for projects to be operational in 1984, these costs are escalated 
at 12 percent per year from January 1980 to obtain the January 1984 prices. 
The estimated costs include all direct costs such as studies, licensing, 
permits, and approvals, but do not include the indirect costs of financing 
and of interest during construction. Since the cost of interest during 
construction will vary depending on the interest rate charged on the funds 
which are available to the site developer, it has been included in the 
fixed annual cost of owning and operating the project. 

The cost of constructing a project (in dollars per kW of installed 
capacity) increases rapidly for projects having capacities below 1000 kW. 
The estimated project cost ranges from $2,200 to $3,500 per kW for projects 
with capacities of 400 kW to 500 kW. From 200 kW to 400 kW, the cost 
increases to $3,500 to $4,500 per kW; and for projects of less than 200 kW, 
the project cost can be expected to exceed $4,500 per kW. 




Blaok Butte Dam, on Stony Creek in Tehema County^ 
ie owned by the U. S. Army Corps of Engineers. A 
9 200-kilowatt hydroelectric power plant at this 
site could generate 31. S million kilohxztthours of 
electricity per year. This amount of energy would 
supply the annual electrical residential needs of 
14j900 people. (Photo by DWR Energy Division) 



41 



9500 



9000 



3500 



,^ 



3000 - 



2500 



o 2000 

a 

0] 

O 



1500 



Figure 8 Estimated Costs of 28 Projects Studied 
by the Department of Water Resources 

1 1 1 1 ! 1 



I 

I 



I3i 



L*g«nd 
A DAM 
■ CANAL 
• PIPELINE 

NOTE: 

See Table 1 1 for Site 
Identification. 



? 



1000 



500 - 



112 
\aI8 



20 



14^ 


\.,7 

N 






2B* 


\ 


n 






10 


V 
X 


'▲ 


5»\l5 


26A 


'^^ 








'«A 








• 








19 



25. 



24 



22 



8 



2000 4000 6000 

Cost Per kW of Capacity (1984 doHars) 



21 



8000 



42 



Annual Cost . The annual cost of ov«ming and operating a hydroelectric proj- 
ect is principally debt payment, paying the interest and a portion of the 
borrowed principal. The remainder of the annual cost pays for operation 
and maintenance, insurance for the equipment, and the replacement of minor 
components that have shorter useful lives than the main generating 
facilities . 

The interest rate for a long-term debt of 20 to 35 years has increased 
significantly since the third quarter of 1979. This reflects the current 
general American inflation and investor concern about the future rate of 
inflation. It is anticipated that the interest rate for hydroelectric 
development will continue at a high level for at least the next five years. 
Prior to the third quarter of 1979, the interest rate for tax-exempt 
bonds — as reflected by the Bond Buyer Index of 20 Bonds — was about 7 per- 
cent, and new, taxable utility bonds averaged 9.5 to 10 percent. From the 
third quarter of 1979 to mid-1980, the interest rate for tax-exempt bonds 
was about 9 percent, while that for taxable utility bonds was 12 to 13 per- 
cent. The interest rate for a loan of the $2 million to $10 million 
required for a small hydroelectric project could be as high as 15 percent 
under conventional financing. 




Hell Hole Reservoir (Lower Bell Bole Dam) ^ on the 
Rubicon River in Flaoer County ^ is owned by the 
Placer County Water Agency. A 400-kilowatt hydro- 
electric power plant at this site could generate 
3 million kilowatthours of electricity per year. 
This amount of energy is equivalent to burning 
SjlOO barrels of oil in a fossil- fuel power plant. 
(Photo by DWR Division of Safety of Dams) 



43 



Figure 9 Annual Cost of Owning and Operating Small Hydroetectiic Projects 



3000 



2500 



2000 



1500 



a 
o 



1000 



500 



9% INTEREST 
36 - YR DEBT 



RANGE 



■T— I r 



I 
I 
I 

I 



i: 



1.3 ■ 
'At 

1.20 
I 

I 






28 




15% INTEREST 
20 - YR DEBT 



1." 



9 A 



I4A BIT 



»2fl 



241 



26-V ? 

21 ^^^ 23 

J I ' "*■** 



L*g«fld 
A DAM 
■ CANAL 
• PIPELINE 



NOTE: 

See Table 1 1 for 
Site identification 



2C 



■ \l6 



• 19 



23 



JL 



X 



J. 



10 12 14 16 18 20 22 

Percentage of Project Cost 



'JL 



24 



26 



28 



44 



The financing of small hydroelectric projects is discussed in 
Appendix H and also shows how interest during construction and the cost of 
financing are included in the fixed annual costs. The range of total 
annual costs is fairly uniform at 13 to 21 percent of project costs for 
hydroelectric facilities with capacities of about 200 kW and greater 
(Figure 9). For hydroelectric facilities of less than 200 kW capacity, the 
annual costs increase significantly because a facility has basic mainte- 
nance and insurance costs regardless of its installed capacity. 

Energy Generation . Besides the head, the annual energy output of a 
particular hydroelectric facility depends on the quantity of water that 
passes through its turbine. A hydroelectric installation at an irrigation 
structure would have flows available during the irrigation season from May 
through September, but there might not be any flow during other months of 
the year. Flood control dams, on the other hand, have normal release 
patterns during the winter and spring months. 

Energy generation (kWh) is equal to the average number of kilowatts 
(kW) — calculated from the head and average flow in the same manner as for 
design capacity — times the number of hours that the head and flow are 
available. These calculations for the 28 selected sites are discussed in 
Appendix C and provide the guidelines for calculating energy generation at 
other facilities. 

Capacity Factor . The capacity factor of a hydroelectric installation is 
the ratio of the energy generated (kWh) to the total amount of energy that 
would be produced if the facility could operate at its design capacity 
throughout the period being considered, usually a year. 

Capacity factors for the 28 preliminary feasibility studies ranged 
between 25 and 90 percent; most sites fell in the range of 40 to 
60 percent. Pipeline installations usually showed higher capacity factors 
because distribution systems usually operate most of the year. The 
capacity factor is a useful, common base for evaluating the relationship 
between the cost and the value (revenues from sales) of generation. 

Utility Pa3rments for Hydroelectric Generation . The value of generation is 
the price a purchaser would pay for the capacity and energy produced by a 
project. This is discussed in detail in Chapter II and Appendix G. In 
mid-1980, the price PGandE would pay for cogeneration averaged about 
6.1 cents per kWh , and PGandE's proposed policy for pricing hydroelectric 
generation averaged about 4.0 to 4.2 cents per kWh . Southern California 
Edison Company's (SCE) published price averaged about 5.1 cents per kWh ; 
and San Diego Gas and Electric Company's (SDG&E) price averaged about 
5.9 cents per kWh. 

These prices escalate along with the price of oil. Using the 
California Energy Commission's (CEC) median price projection for future oil 
and a 12 percent inflation rate, the value of hydroelectric energy in 1984 
would be about 11.1 cents per kWh under PGandE's cogeneration rate and 
8.7 cents per kWh under its proposed hydroelectric rate. The value of 
capacity, if applicable, would be in addition to the value of energy for a 
total of about 12.3 cents per kWh for cogeneration and 8.9 cents per kWh 
for hydroelectric generation in 1984. The comparable SCE value for 1984 



45 



8000 



7000 



6000 



5000 



5 

a 
to 

s. 

o 4000 



o 
o 

o 
"o 

0. 



3000 



2000 - 



1000 



Figure 10 Preliminary Assessment of 28 Sites Studied 
by the Department of Water Resources 

, ^ 7 ^ 



9% INTEREST 35-YEAR DEBT 

A" 



COST EFFECTIVE 
AFTER 1989 




COST EFFECTIVE IN 1984 



1 "»A • 



L»o«fMl 
▲ DAM 
■ CANAL 
• PIPELINE 



20 



40 60 

Capacity Factor (percentage) 



80 



100 



46 



would be 10.1 cents per kWh for energy plus about 1 cent for capacity, and 
SDGandE's value would be 11.7 cents for energy plus about 1.3 cents for 
capacity. The values estimated for other years are shown in Table 8, 
Chapter II. To estimate the number of sites that are cost effective, the 
price that utilities would pay for hydroelectric generation was assumed to 
be 11.1 cents per kWh in 1984 and 20.6 cents per kWh in 1989. 

Assessment of 28 Sites by the Department of Water Resources 

According to the rates published by PGandE, SDG&E, and SCE, the value 
of hydroelectric generation is primarily the energy value because the 
avoided costs are based on oil-fired generation. The average value of 
hydroelectric generation — the published price that would be paid for such 
generation — can be expressed as the break-even project cost of a hydroelec- 
tric facility. The break-even point is reached when the annual cost of 
owning and operating the project equals the revenues received from the sale 
of the project's generation. For example, the break-even cost for a 
project financed at 1 2 percent interest for 20 years (resulting in an 
annual cost of 19 percent of project cost), operating at a 50 percent 
capacity factor, and an energy value of 11.1 cents per kWh, is equal to 
($0,111 X 0.5 X 8760/0.19) or about $2560 per kW. The break-even costs 
will be different with different interest rates, terms of financing, and 
energy values. The allowable project cost is directly related to capacity 
factor. 

The relative economic feasibility of each of the 28 representative 
sites is shown in Figure 10. The sloped lines represent the break-even 




Conibie Darij on the Bear River in Nevada County ^ is ouned 
by the Nevada Irrigation District. A 1 OOO-kiloTJott 
hydroelectric power plant at this site could generate 
4 million kilowatthours of electricity per year. This 
amount of energy is equivalent to burning 6,800 barrels 
of oil in a fossil-fuel power plant. 

(Photo by DWR Division of Safety of Dams) 



47 



Figure 1 1 Estimated Project Costs For 42 Sites Studied by Others 

16.000 



15,000 



14,000 



13,000 - 



^ 



10,000 - 



^ 



=> 6,000|- 

c 

o 



c 
O 
r 5,000 



u 

(D 

Q. 
(S 

O 



4.000 - 



3.000 



2.093 



1,990 



^^ 



T 



k20o 



kte 



Trend line from figure 8 



29a 



33i 



1,20b 



13^40 ^41 



135 



i34 



26" 



'19 



28 



30^ 

I 

▲20 c 

\ 
\ 
\ 
\ 



_ 4 J 2 7oIaSU2I 
'0 ?l •32 2?C~ 



37 



I 

Legend 
▲ DAM 
■ CANAL 
• PIPELINE 

NOTE: 

See Table 1 1 for Site 
Identrfication. 



22^27 






^^ 



e 



X 



X 



X 



X 



1000 



tL^^ 



2000 3000 4000 

Cost of Capacity (1984 dollars per kWJ 



5000 



6090 



48 



project costs for a 9 percent interest rate and a 35-year terra of debt, 
assuming the energy value is 11.1 cents per kWh in 1984 and 20.6 cents in 
1989. The numbers and symbols represent facilities and correspond to the 
sequence used for identifying the 28 sites listed in Table 11 and discussed 
in Appendix C. 

Sixteen of the 28 facilities would be cost effective in 1984, and 
represent a total installed capacity of 21 875 kW and an annual energy 
generation of 91 million kWh. Five additional sites would be cost effec- 
tive by 1989; the remaining 7 sites would not prove cost effective under 
current fuel cost projections. 

The cost of generation at each of the 28 sites is tabulated in cents 
per kWh in Table 11. 

Assessment of 42 Sites by Others 

The studies prepared by others vary in scope from preliminary assess- 
ments to full-fledged feasibility studies. Because the studies were pre- 
pared at different times by different engineering firms or by owners, there 
is no common basis for estimating costs. For these reasons, the results 
presented here should be used only as an indication of cost effectiveness . 
The estimated project costs of the 42 sites, are presented in Figure 11. 
The numbers and symbols represent facilities and correspond to the sequence 
used for identifying the 42 sites listed in Table 11 and discussed in 
Appendix D. The dashed trend line shown in the figure was developed from 
data collected during the 28 studies prepared by the Department. 

Before assessing the economic feasibility of the 42 facilities, the 
project costs presented in the reports were increased at 12 percent annu- 
ally to cover inflation to 1984. The annual cost of owning and operating 
each proposed f>ower plant was also estimated based on the information 
developed in the Department's studies. These annual costs (as a percentage 
of the project costs) are given for a range of interest rates and terms of 
debt service (Figure 9). 



The cost effectiveness of each of the 42 sites was estimated by 
comparing annual costs to the expected annual revenue from project 
generation. The relative economic feasibility of each of the 42 sites, 
based on energy values of 11.1 cents per kWh in 1984 and 20.6 cents in 
1989, is shown in Figure 12. The break-even costs are shown for an 
interest rate of 9 percent and a 35-year term of debt. 

Based on the estimated energy value of 11.1 cents per kWh, 36 of the 
42 facilities would be cost effective in 1984. They represent a total 
installed capacity of 134 135 kW and an annual generation of 610 million 
kWh. Five additional facilities would be cost effective by 1989; only one 
facility would not prove cost effective under current fuel cost 
projections . 

The cost of generation at each of the 42 sites is tabulated in cents 
per kWh in Table 11. 



49 



Figure12 Preliminary Assessment of 42 Sites Studied by Others 



6000 



5000 - 



4000 



(S 

a. 
to 
3 
% 3000 



(0 

O 
O 

u 

.£. 
o 

w 



2000 - 



1000 - 



r— 




' / 


7 








9% INTEREST 35-YEAR DEBT / 

/ / 




COST EFFECTIVE 


J ... 


/ 


- 


AFTER 1989 


/ 


/ 








/ ^ 


/ 








/ • 


/ 








/COST EFFECTIVE 


/ 






1 


1 BY 1989 / 


A'6 
A^ 




^ 


1 


^' A- / 


COST EFFECTIVE IN 1984 




Sf 




"%y 




_ 


■7 






A& 








y A 

&/ A25 


A^^ 






4 


t/ 2 A 






-7 . 


■39 


j^20c 

18* 
A20b 


22 


J f 


32 ^20o 
28 37" .t 


.2 A30 
A^' 








lOa ,■ 11^29 








▲" 


■l9 

1 


Legend 
A DAM 
■ CANAL 
• PIPELrNE 

L 1 1 





20 



40 60 

Capacity Factor [percentage) 



80 



100 



50 



Assessment of 215 Sites From Data on Questionnaires 

The Department's questionnaires provided sufficient information to 
estimate the installed capacity, energy generation, and capacity factor for 
215 sites. The head and flow data from the questionnaires are assumed to 
be approximations and, in many instances, may be optimistic estimates of 
the resource. 

Although these 215 sites may be suitable for power development, 
on-site inspections by qualified engineers, and refined head and flow data 
are needed before their cost effectiveness as small hydroelectric develop- 
ments can be confirmed. To estimate their cost effectiveness, the cost 
information developed from the Department's 28 feasibility studies was used 
as a basis. The cost in dollars per kW, based on the estimated installed 
capacity, was obtained from Figure 8. The annual cost of owning and 
operating each site was then estimated from Figure 9. 

At an interest rate of 9 percent, a 35-year debt repayment period, and 
an energy value of 11.1 cents per kWh , 115 sites would be cost effective in 
1984; they represent a total installed capacity of 311 290 kW and an annual 
generation of 1.5 billion kWh. An additional 63 sites would be cost 
effective by 1989; 37 sites would not prove cost effective under current 
fuel cost projections. 

The cost of generation for each of the 215 sites is tabulated in cents 
per kWh in Table 11 . 

Summary of Assessment 

The estimates of the economic feasibility of the 285 potential 
hydroelectric sites at existing facilities were based on several factors: 

(1) Cost data developed from the Department's preliminary 
feasibility studies of 28 sites; 

(2) The estimated cost and estimated annual generation at 
42 sites studied by others; 

(3) The estimated capacity and estimated energy generated at 
215 sites whose information was obtained from 
questionnaires ; 

(4) A 35-year debt at an assumed interest rate of 9 percent; and 

(5) Estimated payment by utilities for hydroelectric generation of 
11.1 cents per kWh in 1984, and 20.6 cents in 1989. 

To determine the number of power plants that would be cost effective 
in 1989, it was assumed that these power plants would be constructed and on 
line by 1984, and that the developer would operate the power plant at a 
loss for the first one to five years. 

Based on these conditions and assumptions the cost effectiveness of 
small hydroelectric development at 285 existing facilities in California 
are listed in Table 11 and summarized in Table 12, and Figure 1. 



51 



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55 



CHAPTER IV 



PROCEDURES FOR SITE DEVELOPMENT 



The procedures for obtaining the permit approvals and environmental 
reviews required for retrofitting small hydroelectric facilities are con- 
siderably less complex than those for most other energy development proj- 
ects of similar size. However, this does not mean that they are simple or 
that they can be completed quickly. In this chapter, the procedures are 
explained in the context of overall facility planning, obtaining approvals, 
design, and construction. As with facility design and construction, most 
prospective small hydroelectric developers should engage a qualified 
consultant to do project planning work and obtain approvals. 

The steps that must be taken to develop a small hydroelectric project 
are listed, in sequence, in Table 13. 

Because some steps can be carried out concurrently, usually only 
about 36 months will elapse between the reconnaissance survey and the full 
operation of the project. If the site owner chooses to apply for a PURPA 



Table 13. 


Steps Required to Develop a Small Hydroelectric Project 


Step 


Estimated Reference in 
Completion Time this Report 



(1) Reconnaissance Survey 

(2) FERC Preliminary Permit Application 

and Processing 

(3) Preliminary Feasibility Study 

(4) DOE Feasibility Loan Application 

and Processing 

(5) Final Feasibility Study 

(6) DOE License Loan Application 

and Processing 

(7) Licensing, Permit Approvals, and 

Environmental Review 

(8) Financing: Short-term and 

Long-term 

(9) Preparation of Plans and 

Specifications 

(10) Manufacture of Equipment 

(11) Construction and Testing 



1-3 days 
4-9 months 

1-3 months 
1 .5-3 months 

4 months 

3 months 

12 months 

4 months 

6 months 

10-12 months 
9-12 months 



Chapter IV 
Appendix C 

Chapter III 
Appendix C 

Chapter IV 
Appendix D 

Appendix C 

Appendix D 

Appendix C 

Appendix E 



67 




Lake Fordycej on Fordyoe Creek in Nevada County^ is owned by 
the Pacific Gas and Electric Company. A 900-kilowatt hydro- 
electric power plant at this site could generate 4 million 
kilowatthours of electricity annually. This amount of energy 
is equivalent to burning 6,800 barrels of oil in a fossil- 
fuel power plant. (Photo by DWR Division of Safety of Bams) 
Title IV loan either to finance the final feasibility study or to apply for 
the FERC license or both, about 3 to 6 months must be added to the 
schedule. Before granting such a loan, however, the U. S. Department of 
Energy (DOE) requires that developers obtain either a preliminary permit or 
a license exemption. 



The steps for developing a small hydroelectric project are discussed 
below. A generalized schedule for the development of a small hydroelectric 
facility is presented in Figure 13. 

Reconnaissance Survey 

The reconnaissance survey is used to determine whether a hydroelectric 
potential exists at a given site. Specifically, the investigator must 
determine how much water falls through what distance. If a field investi- 
gation and preliminary computation show that the site has little or no 
potential, further development can stop before the owner or developer has 
made any significant investment. 

Preliminary Permit Application 

If the reconnaissance results are favorable, the developer next 
applies to FERC for a preliminary permit or an exemption. [A sample 
application and the instructions for completing it are included in 
Appendix F.] The preliminary permit gives a permittee priority in applying 
for a FERC license to develop the site. A FERC license exemption provides 
exclusive development rights to the site owner. The preliminary permit or 
license exemption is a prerequisite to obtaining a DOE loan for the final 
feasibility study. 



68 



Figure13 Typical Costs and Schedule for Developing a Small Hydroelectric Project 




B. SCHEDULE 
^Preliminary 
/ Feasibility Study 



DOE 
Feasibility 



DOE 
Licensing 



Process Study Process 



Manufacture Equipment 



Field Surveys 



Design and 



Construction 



FERC Licensing 



Specifications 



State and Other Approvals 



_] i I L 



-J I I L_ 



J I I L_ 



16 20 

Time in Months 



SOURCE; u s c E 



Funding by Site Developer and DOE 



Short Term 
Financing 



Long Term Financing 




Dahlia Drop, on the Central Main Canal in Imperial 
Counti/j is owned by the Imperial Irrigation District. 
A 225-kilowatt hyS^'oeleotric power plant at this site 
could generate 1 million kilowatthours of electricity 
per year. This amount of energy is equivalent to burn- 
ing 1,700 barrels of oil annually in a fossil-fuel plant. 
(Photo by DWR Energy Division) 



69 



Preliminary Feasibility Study 

In the preliminary feasibility study, the full potential of the site 
is realistically assessed at a minimum cost. The results of the study will 
help the developer to decide whether to spend more money, apply for a 
Title IV loan to finance the final feasibility study, or both. 

The preliminary feasibility study presents the greatest financial 
risk. Therefore, a developer (without in-house capability) should have a 
qualified engineer determine whether the site lacks potential due to tech- 
nical, economical, or environmental reasons; whether it would be economic- 
ally marginal during its early years of operation; or whether it shows a 
definite promise of being both technically and economically feasible. 
Examples of preliminary feasibility studies are presented in Appendix C. 

The cost of a preliminary feasibility study should be about $3,000 to 
$5,000, depending on the complexity of the site and the availability of 
reference material such as drawings of existing structures, streamflow 
data, etc. The study should provide enough information to support an 
application for a Title IV loan to finance the final feasibility study. 

Feasibility Loan Application and Processing 

A loan program established by DOE can provide up to 90 percent of the 
cost of the final feasibility study at a rate of 7.25 percent interest. A 
developer can obtain up to $50,000 for a ten-year term; repayment is not 
required during the first four years. Moreover, if the final feasibility 
study reveal that the proposed project is not technically or economically 
sound, DOE may forgive the repayment of the loan. 

















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Thermalito Aftevhay River Outlet, adjacent to the Feather River 
in Butte County, is owned by the California Department of Water 
Resources. A 13 000-kilowatt hydroelectric power plant at this 
site could generate 43 million kilowatthours of electricity per 
year. This amount of energy is equivalent to burning 73,000 
barrels of oil annually in a fossil-fuel power plant. 

(Photo by DWR Energy Division) 



70 




Thermalito Diversion Damy on the Feather River in Butte County^ 
is oimed by the California Department of Water Resources . A 
3 000-kilowatt hydroelectric power plant at this site could 
generate 24 million kilowatthaurs of electricity annually. This 
amount of energy is equivalent to burning 41,000 barrels of oil 
in a fossil-fuel power plant. (Photo by DWE Energy Division) 



Final Feasibility Study 

If the results of the preliminary feasibility study are favorable, the 
next step is to refine the preliminary estimates of the project's capacity, 
energy output, and construction costs. In some cases, if feasibility is 
definitely indicated and sufficient records of streamflow are available, 
this refinement process can await final design. In other cases, the 
results of the preliminary feasibility study can be used to prepare the 
FERC license application. Usually, however, the estimates of capacity, 
streamflow, and costs will have to be refined during a final feasibility 
study in order to determine the optimal size of the turbine/generator. 

The feasibility study must 

1) determine the installed capacity, the number of generating units 
required (usually one unit for a small hydroelectric facility), and 
the size and type of supporting physical works; 

2) prepare detailed estimates of construction costs; 

3) develop ownership and operating criteria for the facility; 

4) estimate energy generation under wet-year, normal, and dry-year 
streamflow conditions; and 



71 



5) identify the constraints on development of the site. Financial, 
legal, environmental, and socioeconomic constraints may affect a 
project adversely or even prevent its development. 

The major factors that influence the layout of the project are the 
head and flow, the performance characteristics of the turbine/generator, 
the size of the structure needed to house the equipment, and the configura- 
tion of the facilities. 

Licensing Loan Application and Processing 

If the results of the final feasibility study are favorable, the next 
step is to apply for a DOE licensing loan. As under the DOE Feasibility 
Loan Program, a developer may obtain up to $50,000 for a ten-year term at 
7.25 percent interest. Part of the loan may be used to defer the cost of 
obtaining the necessary environmental and other approvals by state, federal, 
and local agencies. 

License and Permit Approvals, and Environmental Review 

The final feasibility study will provide enough technical information 
for the license and permit applications. The licensing and approval pro- 
cesses (discussed in detail in Appendix F) are quite involved and require 
about a year to complete. Since similar information is required for the 
various state and federal applications, totally new information need not be 
generated for each application. It may be necessary to obtain licenses, 
permits, certificates, and approvals from several state, federal, and local 
agencies (Table 14). The authority, responsibility, and requirements of 
these federal, state, and local agencies are discussed in Appendix F. 



Table 14. Agencies Whose Approvals for Small Hydroelectric Projects Are 
Required 



Federal State Local 



Federal Energy Regulatory Department of Fish and Game Counties 

Commission (FERC) 

Department of Water Resources Special Districts 
U. S. Army Corps of 

Engineers State Lands Commission Municipalities 

U. S. Bureau of Land State Water Resources 
Management Control Board 

U. S. Forest Service Office of State Treasurer 

(District Securities Division) 

U. S. Water and Power 
Resources Service 



72 



Financing 

Short-Term Financing . As soon as the FERC license is approved and it is 
known that other approvals are imminent, the developer should begin to 
develop the final design, and prepare specifications and bid documents. By 
this time, the loan funds for the feasibility study and licensing will be 
running out, and long-terra financing for construction, such as bonds and 
other government loans, will probably not be arranged yet. 

To finance the project at this stage, a developer can use a variety of 
financial resources, including private financing, certain government loans, 
or a combination of the two (see Appendix H). For this phase of the proj- 
ect, a developer should consult an experienced financial adviser concerning 
short-term, and long-term financing. 

Long-Term Financing . Long-term financing arrangements should be completed 
by the time the order for turbine/generator is placed. The manufacture of 
the hydroelectric generating equipment requires from 10 to 12 months. The 
manufacturer will require a down payment and subsequent progress payments 
while the equipment is being fabricated. 

Sources of long-term loans include bonds, private financing, and 
government loans. Tax-exempt bonds, such as general- obligation or certain 
revenue bonds, can usually be issued by public agencies, and taxable 
revenue bonds can be issued by either public or private agencies. Private 
financing includes equity and mortgage loans. Income tax credits provided 
by the Windfall Profits Tax Act of 1979 encourage private financing. 
Several government agencies issue construction loans at low-interest, 
usually around five percent; they include the U.S. Department of Housing 
and Urban Development and the U.S. Department of Agriculture. 

The California Legislature has established several programs to assist 
renewable resource technologies and to provide financing assistance for the 
development of small hydroelectric projects. Appendix H contains descrip- 
tions of these programs and the name and address of the agencies respons- 
ible for their administration. 

Design and Construction 

Preparation of Plans and Specifications . The preparation of contract plans 
and specifications requires about 6 months. 

Manufacture of Equipment . Since it takes about one year to manufacture the 
turbine and generator, the contract for those items should be awarded as 
soon as possible. Their manufacture should proceed concurrently with 
design and construction of the civil works. Usually, a separate contract 
for the turbine/generator is awarded before the design of the civil works 
has been completed. Delivery of the turbine/generator should be coordin- 
ated with construction of the plant structure. 

Construction and Testing . Construction usually takes about 9 to 12 months, 
depending on the complexity of the project. Following this, a month or two 
of operational testing will be required. This should be conducted by an 
engineer and should include the training of operation and maintenance 
personnel . 



73 




^Sij^ 



Rollins Dorr,, on the Bear River in Nevada County, is owned by the 
Nevada Irrigation District. Here, a 12 OOO-kilowatt hydroelectric 
power plant generates 60 million kilowatthours of electricity per 
year. This amount of energy is equivalent to burning 102,400 
barrels of oil in a fossil-fuel power plant. 

(Tudor Engineering Company Photo) 



74 



GLOSSARY 



ACRE-FOOT (ac-ft, AF) — The amount of water required to cover one acre to 
a depth of one foot. This is equivalent to 325,851 gallons, 
43,560 cubic feet, 1,233.5 cubic metres, or 1.2335 cubic dekametres. 

ADVERSE WATER CONDITIONS — Water conditions that limit the hydroelectric 
generation by either a low water supply or a reduced HEAD.* 

ALTERNATING CURRENT (ac, AC) — Electricity that reverses its direction of 
flow periodically, as contrasted to DIRECT CURRENT. 

AMORTIZATION — The paying of a debt with installment payments or with a 
SINKING FUND. Also writing off expenditures by prorating them over a 
period . 

APPRAISAL STUDY — A preliminary feasibility study made to determine if a 
detailed FEASIBILITY STUDY is warranted. Also called a reconnaissance 
study . 

AVAILABILITY FACTOR — The percentage of time a plant is available for 
power production. 

AVERAGE -WATER YEAR — The average annual flow of water available for 
hydropower generation calculated over a long period, usually 10 to 
50 years. 

AVOIDED COST — The payment made for the capacity and energy of a small 
power project; such payment equals the cost to a utility of obtaining 
and operating additional generating units, or to purchase power from 
another source, if this power were not available. Also called avoidable 
cost . 

BARREL (bbl) — The measure used for crude oil; it is equal to 42 U.S. 
gallons (gal). 

BARREL-OF-OIL EQUIVALENT — (BOE). A unit of energy equal to the energy 
contained in a BARREL of crude oil or 5,800,000 Btu. 

BASE LOAD — The amount of electric power needed to be delivered at all 
times and all seasons. 

BASE LOAD STATION — A power generating station usually operated at a 
constant output to take all or part of the BASE LOAD of a system. 

BENEFIT-COST RATIO (B/C) — The ratio of the present value of the benefit 
(e.g. revenues from power sales) to the present worth of the project 
cost . 

BOE ~ See BARREL-OF-OIL EQUIVALENT. 



*Capitalized terms indicate those defined elsewhere in this glossary. 



75 



BRITISH THERMAL UNIT (Btu) — The quantity of heat required to raise the 
temperature of one pound of water one degree Fahrenheit. 

BTU -- See BRITISH THERMAL UNIT (Btu). 

BLM — Bureau of Land Management. 

CALIFORNIA ENVIRONMENTAL QUALITY ACT (CEQA) — An act, passed in 1970, that 
requires that the environmental impact of most projects and programs be 
identified. Among its important provisions is one requiring that a 
detailed statement of the environmental impact of, and alternatives to, 
a project be submitted to the California State or local government 
before the project can begin. 

CAPACITY -- The maximum power output or the load for which a generating 
unit, generating station, or other electrical apparatus is rated. 
Common units include kilovolt-ampere (kVA), KILOWATT (kW) , and MEGAWATT 
(MW). 

CAPACITY FACTOR — The ratio of the energy that a plant produces to the 
energy that would be produced if it were operated at full capacity 
throughout a given period, usually a year. Sometimes called the plant 
factor. 

CAPACITY VALUE — The part of the market value of electric power that is 
assigned to DEPENDABLE CAPACITY. 

CAPITAL EXPENDITURES — The construction cost of a new facilities 

(additions, betterments, and replacements) and expenditures for the 
purchase or acquisition of existing utility plant facilities. Also 
called capital outlay. 

CAPITAL OUTLAY — See CAPITAL EXPENDITURES. 

CAPITALIZED COST — A method used to compare the costs of alternatives; it 
is equal to the sum of the initial costs and the present worth of annual 
payments, such as operation and maintenance costs. 

CAPITAL RECOVERY — See DEBT SERVICE. 

CAPITAL RECOVERY FACTOR — A factor used to convert an investment into an 
equivalent annual cost at a given interest rate for a specified period. 

CDWR -- California Department of Water Resources; also DWR. 

CEC — California Energy Commission. (Officially, the Energy Resources 
Conservation and Development Commission.) 

CEQA — CALIFORNIA ENVIRONMENTAL QUALITY ACT. 

CFS — CUBIC FEET PER SECOND. 

CHECK STRUCTURE — A structure where water flow is regulated and measured. 

CIRCUIT BREAKER — A switch that automatically opens to cut off an electric 
current when an abnormal condition occurs. 



76 



CIVIL WORKS — All the works of a facility associated with plant 

structures, impounding channeling, and emergency release of water, etc. 

COGENERATION — The use waste heat from an industrial plant to drive 
turbine-generators for electricity generation. Also, the use of 
low-pressure exhaust steam from an electric generating plant to heat an 
industrial process or a space. 

CPUC — California Public Utilities Commission, also PUC . 

CUBIC FEET PER SECOND (cfs, ft^/s) — A flow equal to 646,317 gallons per 
day or 0.028317 cubic metres per second (m-'/s). Also called a SECOND 
FEET. 

CRITICAL HEAD — The HEAD at which the output of a turbine at full gate 
equals the NAMEPLATE RATING of an associated GENERATOR. 

DEMAND -- The rate at which electrical energy is delivered to a system, to 
part of a system, or to a piece of equipment; it is usually expressed in 
KILOWATTS, MEGAWATTS, etc. 

DESIGN HEAD — The HEAD at which the RUNNER of a turbine is designed to 
provide the highest efficiency. 

DEBT SERVICE — The principal and interest payments made on a debt used to 
finance a project. Also called capital recovery. 

DEPENDABLE CAPACITY — The minimum capacity available at any time during a 
study period. This value is generally determined by optimizing plant 
operation during the driest period when the least water is available. 

DIRECT CURRENT (dc, DC) — Electricity that flows continuously in one 
direction, as contrasted with ALTERNATING CURRENT. 

DOE — U. S. Department of Energy. 

DRAFT TUBE — A large tube that takes the water discharged from a TURBINE 
at a high velocity and reduces its velocity by enlarging the 
cross-section of the tube. 

DUMP ENERGY — Energy generated by water that cannot be stored or conserved 
and when such energy is beyond the need of the producing utility. 

DWR — California Department of Water Resources, also CDWR. 

EFFICIENCY — The ratio of the output to the input of energy or power, 
usually expressed as percentage. 

EIR — An Environmental Impact Report prepared to satisfy the requirements 
of the CALIFORNIA ENVIRONMENTAL QUALITY ACT (CEQA) . 

EIS — An Environmental Impact Statement prepared to satisfy the require- 
ments of the Federal NATIONAL ENVIRONMENTAL POLICY ACT (NEPA). 



77 



ELECTRICAL ENERGY UNITS — Common units used to measure electrical energy 
include KILOWATTHOURS (kWh) and GIGAWATTHOUR (GWh, million kWh). A 
100-watt light bulb lit for ten hours will consume one KILOWATTHOUR 
(kWh) of electrical energy. A one-MEGAWATT generating unit will produce 
1000 kWh if it runs for one hour at full CAPACITY. 

END USER -- Any ultimate consumer of electricity or of any type of fossil 
fuel (petroleum, coal, natural gas). 

ENERGY -- The capability of doing work which occurs in several forms such 
as potential, KINETIC, thermal, and nuclear energy. One form of energy 
may be changed to another; the kinetic energy of falling water can be 
used to drive a turbine where the energy is converted into mechanical 
energy which can drive a generator to produce ELECTRICAL ENERGY. 

ENERGY DISSIPATER -- A device used to reduce water pressure to a level safe 
for certain uses. 

EXTRA HIGH VOLTAGE (EHV) — A term applied to voltage levels of transmis- 
sion lines which are higher than the voltage levels commonly used. At 
present, electric utilities consider EHV to be any voltage of 
345,000 volts or higher. See ULTRAHIGH VOLTAGES. 

FEASIBILITY STUDY — An investigation to develop a project and definitively 
assess its desirability for implementation. 

FEDERAL ENERGY REGULATORY COMMISSION (FERC) — An agency in the U. S. 

Department of Energy, which licenses non-Federal hydropower projects and 
regulates the interstate transfer of electrical energy. 

FERC -- FEDERAL ENERGY REGULATORY COMMISSION. 

FIRM CAPACITY — The load-carrying ability of a plant that would probably 
be available to supply energy for meeting LOAD at any time. 

FIXED COSTS — Costs associated with plant investment, including DEBT 
SERVICE, interim replacement, and insurance. 

FLOW-DURATION CURVE — A curve of flow values plotted in descending order 
of magnitude against time intervals, usually in percentages of a spec- 
ified period. For example, the curve might show that over a period of a 
year, a river flows 500 CFS or more 10 percent of the time, and 100 CFS 
or more 80 percent of the time. 

GENERATOR — A machine that converts mechanical energy into ELECTRTICAL 
ENERGY. 

GIGAWATTHOUR (GWh) — One million KILOWATTHOURS (kWh). 

GROUND WATER -- The supply of water under the earth's surface, as con- 
trasted to SURFACE WATER. 



78 



HEAD — The difference in elevation between two water surfaces. In hydro- 
power, the net head refers to the difference in elevation between the 
headwater surface above and the tailwater surface below a HYDROPOWER 
PLANT, minus friction losses. 

HORSEPOWER (hp) — The equivalent of 0.746 KILOWATT (kW). 

HYDROPOWER PLANT — An electric power plant in which the energy of falling 
water is converted into electricity by turning a turbine-generator unit. 
Also called a hydroelectric power plant, a hydroelectric plant, or 
simply a hydro plant. 

IMPOUNDMENT — A reservoir or artificial pond created behind a dam. 

INCREMENTAL COST — The additional cost incurred when generating an added 
amount of power. 

INSTALLED CAPACITY — The total of the CAPACITIES shown on the nameplates 
of the generating units in a HYDROPOWER PLANT. 

INTERRUPTIBLE ENERGY — Energy that can be curtailed at the supplier's 
discretion. 

KILO (k) — A prefix meaning one thousand. 

KILOWATT (kW) — One thousand watts (W) or 1.34 HORSEPOWER (hp). 

KILOWATTHOUR (kWh) — One thousand watthours (Wh) - the amount of ELEC- 
TRICAL ENERGY produced or consumed by a one-KILOWATT unit for one hour. 

KINETIC ENERGY — The energy of motion; the ability of an object to do work 
because of its motion. 

LOAD — The amount of power required at a given point or points in an elec- 
tric system, 

LOAD FACTOR — The ratio of the average load to the maximum load during 
a given period. 

LOW-HEAD HYDROPOWER — Hydropower that operates with a head of 20 metres 
(66 feet) or less. 

MARKET VALUE — The value of power at the load center, as measured by the 
cost of procuring equivalent alternative power to the market. 

MEGA (M) — A prefix meaning one million. 

MEGAWATT (MW) — One thousand KILOWATTS (kW) or one million watts (W) . 

MILL — One tenth of a cent or one thousandth of a dollar. 

MGD — Million gallons per day, equivalent to 1.547 CUBIC FEET PER SECOND 
(cfs). 



79 



MWD — The Metropolitan Water District of Southern California. 

NAME PLATE RATING — The full-load continuous rating of a GENERATOR or other 
electrical equipment under specified conditions as designated by the 
manufacturer, and written on the nameplate. 

NATIONAL ENVIRONMENTAL POLICY ACT (NEPA) — An act, passed in 1969, 

requiring that the environmental impact of most projects and programs be 
identified. Among its important provisions is one requiring a detailed 
statement of environmental impact of, and alternatives to, a project to 
be submitted to the federal government before the project can begin. 

NON-FOSSIL ENERGY — Energy from sources other than fossil; non-fossil 

energy sources include nuclear, wind, tide, biomass , geothermal , water, 
and solar sources. 

NEGATIVE DECLARATION — The document which satisfies the CEQA requirement 
if no significant environmenal impacts would result from a project as 
determined by an initial study. 



OFF-PEAK — The time of day and week when the demand for electricity is 
low; see ON-PEAK. 

ON-PEAK — The time of day and week when demand for electricity in a region 
is high. 

OUTAGE — The period in which a facility is out of service. 

OUTAGE, FORCED — The shutdown of a facility for emergency reasons. 

OUTAGE, SCHEDULED — The shutdown of a facility for inspection or 
maintenance, as scheduled. 

OUTPUT — The amount of power or energy delivered from a piece of equip- 
ment, a station, or a system. 

PEAKING UNIT — An auxiliary electric power system that is used to supple- 
ment the power supply system during periods of peak demand for elec- 
tricity. Peaking units are usually old, low cost, inefficient units 
having a high fuel cost, or hydroelectric units having low FIRM 
CAPACITY. 

PENSTOCK — A pressure pipe used to carry water to a TURBINE. 

PGandE — Pacific Gas and Electric Company. 

PLANT FACTOR ~ See CAPACITY FACTOR. 

PRELIMINARY PERMIT — An initial permit issued by the FEDERAL ENERGY 

REGULATORY COMMISSION (FERC) for hydropower projects. The permit does 

not authorize construction, but during the permit's term of up to 

36 months, the permittee is given the right of priority-of-application 



80 



for a license while completing the necessary studies to determine the 
engineering and economic feasibility of the proposed project, the market 
for the power, and all other information necessary for inclusion in an 
application for license. 

PSI — A unit of pressure as measured in pounds per square inch. 

PUC ~ See CPUC. 

PUMPED-STORAGE PLANT — A HYDROPOWER PLANT which generates electricity 
during periods of high demand by using water previously pumped into a 
storage reservoir during periods of low demand. Pumped storage returns 
only about two-thirds of the electricity put into it, but it can be more 
economical than obtaining and operating additional generating PEAKING 
UNITS. 

PURPA — Public Utility Regulatory Policies Act of 1978. This act requires 
utilities to purchase power from and interconnect with a privately 
developed facility and mandates the state utility regulatory agency to 
set a "just and reasonable price." 

QUADRILLION — Equivalent to 1 x lO^^^ 

QUADRILLION BTU (Quad) — An amount of energy equal to the heat value of 
965 billion cubic feet of gas, 175 million barrels of oil (BOE), or 
38 million tons of coal. 

RECONNAISSANCE STUDY — See APPRAISAL STUDY. 

REHABILITATION — The restoration of an abandoned power plant to produce 
energy. 

RETROFITTING — Furnishing a plant with new parts or equipment not 

purchased or available at the time of manufacture or construction. In 
hydropower development, the term may refer to the installation of 
electric generating components at existing water facilities to produce 
electricity. 

RIPARIAN RIGHTS — The rights of a land owner to the water on or bordering 
his property, including the right to prevent diversion or misuse of 
upstream water. 

ROYALTY — The portion of the proceeds paid to the title holder in exchange 
for exploitation of a property. 

RPM — Revolution per minute. 

RUNOFF — The portion of rainfall, melted snow or irrigation water that 
flows over the surface and ultimately reaches streams. 

RUNNER — The part of a TURBINE, consisting of blades on a wheel or hub, 
which is turned by the pressure of high-velocity water. 

RUN-OF -THE -RIVER PLANT — A hydropower plant that uses the flow of a stream 
as it occurs with little or no reservoir capacity for storing water. 
Sometimes called a "STREAM FLOW" plant. 



81 



SBA — Small Business Administration. 

SCE -- Southern California Edison Company. 

SDG&E — San Diego Gas & Electric Company. 

SECOND-FEET — CUBIC FEET PER SECOND (cfs). 

SEEPAGE — Water that flows through the soil. 

SERVICE AREA -- An area to which a utility system supplies electric 
service . 

SINKING FUND — A fund set up to accumulate a certain amount in the future 
by collecting a uniform series of payments. 

SPILLWAY — A passage used for running surplus water over or around a dam. 

SPINNING RESERVE — Generating capacity that is on the line in excess of 
the load on the system ready to carry additional electrical LOAD. 

STANDBY SERVICE — Service that is not normally used, but is available, in 
lieu of or as a supplement to, the usual source of supply. 

STREAM FLOW — The amount of water passing a given point in a stream or 
river in a given period, usually expressed in CUBIC FEET PER SECOND 
(cfs), or MILLION GALLONS PER DAY (mgd, MGD). 

SUBSTATION — An assemblage of equipment used to switch and/or change or 
regulate the voltage of electricity. 

SURFACE WATER — Water on the earth's surface that is exposed to the atmos- 
phere such as rivers, lakes, oceans, as contrasted to GROUND WATER. 

SURPLUS ENERGY — Generated energy that is beyond the immediate needs of 
the producing system. This energy is usually sold on an interrupt ible 
bas is . 

SWITCHING STATION — An assemblage of equipment used for the sole purpose 
of tying together two or more electric circuits through selectively 
arranged switched that permit a circuit to be disconnected in case of 
trouble or to change electric connections between circuits. A type of 
SUBSTATION. 

TAILRACE — The channel, downstream of the DRAFT TUBE, that carries 
the water discharged from the TURBINE. 

THERM — The equivalent of 100,000 BRITISH THERMAL UNITS (Btu). 

THERMAL PLANT -- An electric generating plant which uses heat to produce 
electricity. Such plants may burn coal, gas, oil, biomass , or use 
nuclear energy to produce thermal energy. 

TRANSFORMER — A device used to change the voltage of ALTERNATING-CURRENT 
(AC) electricity. 



82 



TRANSMISSION — The act or process of transporting ELECTRICAL ENERGY in 
bulk from a source or sources of supply to other principal parts of a 
system or to other utility systems. 

TURBINE — A machine in which the pressure or KINETIC ENERGY of flowing 
water is converted to mechanical energy which in turn can be converted 
to ELECTRICAL ENERGY by a GENERATOR. 

ULTRAHIGH VOLTAGES (UHV) — Voltages greater than 765,000 volts. See EXTRA 
HIGH VOLTAGE (EHV). 

ULTRALOW HEAD — HEAD of up to 3 metres (9.8 feet). 

USCE — U. S. Army Corps of Engineers. 

USGS — U. S. Geological Survey. 

WATERSHED -- The region draining into a stream. 

WATER TABLE — The upper limit or surface of the GROUNDWATER. 

WATER TREATMENT -- The purification of water to ensure its potability or 
safety for disposal, or to permit alternative use or reuse. 

WEIR — A dam in a stream to raise, divert the water, or to regulate the 
flow. 

WHEELING — The transportation of electricity by an electric utility over 
its lines for another utility. 

WICKET GATES — Gates at the entrance of a turbine used to control water 
flow into a TURBINE. 

WORKING CAPITAL — The amount of cash or other liquid assets that a company 
must have on hand to meet the current costs of operations until it is 
reimbursed by its customers. Sometimes the term is used to mean the 
difference between current and accrued assets and current and accrued 
liabi 1 it ies . 

WPRS — U. S. Water and Power Resources Service (formerly U. S. Bureau of 
Reclamation) . 

YIELD — the amount of water which can be supplied from a reservoir or a 
water source in a specified period. 



82256—950 4-81 5M 



83 



CONVERSION FACTORS 



Quanlity 



To Convert from Metric Unit 



To Customary Unit 



Multiply Metric 
Unit By 



To Convert to Metric 

Unit Multiply 
Customary Unit By 



Length 



Area 



Volume 



Flow 



Mass 

Velocity 

Power 

Pressure 

Specific Capacity 



millimetres (mm) 

centimetres (cm) for snow depth 

metres (m) 

kilometres (km) 

square millimetres (mm') 

square metres (m') 

hectares (ha) 

square kilometres (km') 

litres (L) 
megalitres 
cubic metres (m^) 
cubic metres (m') 
cubic dekametres (dam') 

cubic metres per second (mVs) 

litres per minute (L/min) 

litres per day (L/day) 
megalitres per day (ML/day) 

cubic dekr.metres per day 
(damVday) 

kilograms (kg) 
megagrams (Mg) 

metres per second (m/s) 

kilowatts (kW) 

kilopascals (kPa) 

kilopascals (kPa) 

litres per minute per metre 
drawdown 



Concentration milligrams per litre (mg/L) 



inches (in) 


03937 


254 


inches (in) 


3937 


2 54 


feet (ft) 


3 2808 


3048 


miles (mi) 


62139 


1 6093 


square inches (in') 


000155 


645 16 


square feet (ft') 


10 764 


0092903 


acres (ac) 


24710 


040469 


square miles (mi') 


3861 


2 590 


gallons (gal) 


26417 


3 7854 


million gallons ( 10" gal) 


26417 


3 7854 


cubic feet (ft') 


35315 


028317 


cubic yards (yd') 


1 308 


76455 


acre-feet (ac-ft) 


08107 


1 2335 


cubic feet per second 


35315 


028317 


(ft'/s) 






gallons per minute 


26417 


3 7854 


(gal/min) 






gallons per day (gal/day) 


26417 


3 7854 


million gallons 


26417 


3 7854 


per day (mgd) 






acre-feet per day (ac- 


08107 


1 2335 


ft/day) 






pounds (lb) 


2 2046 


45359 


tons (short, 2,000 lb) 


1 1023 


90718 


feet per second (ft/s) 


3 2808 


3048 


horsepower (hp) 


1 3405 


746 


pounds per square inch 


14505 


6 8948 


(psi) 






feet head of water 


33456 


2 989 


qallons per minute per 


08052 


12419 



Electrical Con- 
ductivity 



microsiemens per centimetre 
(uS/cm) 



foot drawdown 

parts per million (ppm) 1 

micromhos per centimetre 1 



1 
1 



Temperature 



degrees Celsius (°C) 



degrees Fahrenheit (°F) 



l18X°C) + 32 (°F-32)/1 



state of California— Resources Agency 

Department of Water Resources 

P.O. Box 388 

Sacramento 

95802